Table of Contents






UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
FORM 10-Q
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SeptemberJune 30, 20192020

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)

Oregon93-0256820
(State or other jurisdiction of

incorporation or organization)
     (I.R.S. Employer          

     Identification No.)          
121 SW Salmon Street
Portland,, Oregon97204
(503) (503) 464-8000
(Address of principal executive offices, including zip code,
and registrant’s telephone number, including area code) 

Securities registered pursuant to Section 12(b) of the Act:
(Title of class)(Trading Symbol)(Name of exchange on which registered)
Common Stock, no par valuePORNew York Stock Exchange
9.31% Medium-Term Notes due 2021POR 21New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
[x] Yes x [ ] No
  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Table of Contents






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

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

 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes [x] No
 
Number of shares of common stock outstanding as of October 25, 2019July 27, 2020 is 89,372,12589,508,545 shares.

Table of Contents


PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBERJUNE 30, 20192020

TABLE OF CONTENTS

3
PART I — FINANCIAL INFORMATION
DefinitionsItem 1.
PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements (Unaudited)
4
4
5
7
89
Item 2.
3731
Item 3.
5856
Item 4.
5856
PART II — OTHER INFORMATION
Item 1.
57
Item 1.1A.
5957
Item 1A.6.
5957
Item 6.
Exhibits
60
SIGNATURE
6158


2
Table of Contents


DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or AcronymDefinition
AFDCAllowance for funds used during construction
AUTAnnual Power Cost Update Tariff
Abbreviation or AcronymDefinition
AFDCColstripAllowance for funds used during construction
AUTAnnual Power Cost Update Tariff
BoardmanBoardman coal-fired generating plant
CartyCarty natural gas-fired generating plant
ColstripColstrip Units 3 and 4 coal-fired generating plant
CWIPConstruction work-in-progress
EPAUnited States Environmental Protection Agency
FERC
FERCFederal Energy Regulatory Commission
FMBsFirst Mortgage Bonds
GAAPAccounting principles generally accepted in the United States of America
GRCGeneral Rate Case
IRPIntegrated Resource Plan
Moody’sMoody’s Investors Service
MWMegawatts
MWaAverage megawatts
MWhMegawatt hour
NASDAQNasdaqNational Association of Securities Dealers Automated Quotations
NVPCNet Variable Power Costs
NYSENew York Stock Exchange
OPUC
OPUCPublic Utility Commission of Oregon
PCAMPower Cost Adjustment Mechanism
RPS
RPSRenewable Portfolio Standard
S&PS&P Global Ratings
SECUnited States Securities and Exchange Commission
TCJAUnited States Tax Cuts and Jobs Act of 2017
Trojan
TrojanTrojan nuclear power plant
WheatridgeWheatridge Renewable Energy Facility


3
Table of Contents


PART I — FINANCIAL INFORMATION

Item 1.Financial Statements.
 
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
AND COMPREHENSIVE INCOME
(Dollars in millions, except per share amounts)
(Unaudited)
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Revenues:
Revenues, net$469  $462  $1,033  $1,032  
Alternative revenue programs, net of amortization—  (2) 9  1  
Total revenues469  460  1,042  1,033  
Operating expenses:
Purchased power and fuel109  105  262  284  
Generation, transmission and distribution77  86  150  163  
Administrative and other74  78  145  149  
Depreciation and amortization104  101  212  202  
Taxes other than income taxes34  33  69  67  
Total operating expenses398  403  838  865  
Income from operations71  57  204  168  
Interest expense, net34  31  67  63  
Other income:
Allowance for equity funds used during construction4  2  7  5  
Miscellaneous income (loss), net3  —  (1) 2  
Other income, net7  2  6  7  
Income before income tax expense44  28  143  112  
Income tax expense5  3  23  14  
Net income39  25  120  98  
Other comprehensive income—  1  1  2  
Comprehensive income$39  $26  $121  $100  
Weighted-average common shares outstanding (in thousands):
Basic89,489  89,357  89,459  89,333  
Diluted89,625  89,561  89,602  89,537  
Earnings per share:
Basic$0.44  $0.28  $1.34  $1.10  
Diluted$0.43  $0.28  $1.34  $1.09  
See accompanying notes to condensed consolidated financial statements.
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Revenues:       
Revenues, net$538
 $525
 $1,570
 $1,469
Alternative revenue programs, net of amortization4
 —
 5
 (2)
Total revenues542
 525
 1,575
 1,467
Operating expenses:       
Purchased power and fuel165
 186
 449
 420
Generation, transmission and distribution78
 72
 241
 212
Administrative and other74
 49
 223
 188
Depreciation and amortization103
 96
 305
 281
Taxes other than income taxes34
 31
 101
 95
Total operating expenses454
 434
 1,319
 1,196
Income from operations88
 91
 256
 271
Interest expense, net32
 31
 95
 93
Other income:       
Allowance for equity funds used during construction2
 2
 7
 8
Miscellaneous income, net3
 —
 5
 —
Other income, net5
 2
 12
 8
Income before income tax expense61
 62
 173
 186
Income tax expense6
 9
 20
 23
Net income55
 53
 153
 163
Other comprehensive income—
 —
 2
 —
Comprehensive income$55
 $53
 $155
 $163
        
Weighted-average common shares outstanding (in thousands):






Basic89,372

89,239

89,346

89,205
Diluted89,594

89,239

89,555

89,205












Earnings per share:










Basic$0.61

$0.59

$1.71

$1.82
Diluted$0.61

$0.59

$1.70

$1.82
        
See accompanying notes to condensed consolidated financial statements.

4
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(Unaudited)




June 30, 2020December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents$303  $30  
Accounts receivable, net204  253  
Inventories109  96  
Regulatory assets—current12  17  
Other current assets108  104  
Total current assets736  500  
Electric utility plant, net7,301  7,161  
Regulatory assets—noncurrent526  483  
Nuclear decommissioning trust47  46  
Non-qualified benefit plan trust37  38  
Other noncurrent assets158  166  
Total assets$8,805  $8,394  
See accompanying notes to condensed consolidated financial statements.

 September 30,
2019		 December 31,
2018
ASSETS   
Current assets:   
Cash and cash equivalents$11
 $119
Accounts receivable, net161
 193
Unbilled revenues73
 96
Inventories91
 84
Regulatory assets—current26
 61
Other current assets54
 90
Total current assets416
 643
Electric utility plant, net7,014
 6,887
Regulatory assets—noncurrent483
 401
Nuclear decommissioning trust46
 42
Non-qualified benefit plan trust37
 36
Other noncurrent assets158
 101
Total assets$8,154
 $8,110
    
See accompanying notes to condensed consolidated financial statements.






5
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Dollars in millions)
(Unaudited)



June 30, 2020December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable$134  $165  
Liabilities from price risk management activities—current40  23  
Short-term debt150  —  
Current portion of long-term debt140  —  
Current portion of finance lease obligation16  16  
Accrued expenses and other current liabilities289  315  
Total current liabilities769  519  
Long-term debt, net of current portion2,676  2,597  
Regulatory liabilities—noncurrent1,362  1,377  
Deferred income taxes385  378  
Unfunded status of pension and postretirement plans249  247  
Liabilities from price risk management activities—noncurrent145  108  
Asset retirement obligations265  263  
Non-qualified benefit plan liabilities101  103  
Finance lease obligations, net of current portion132  135  
Other noncurrent liabilities75  76  
Total liabilities6,159  5,803  
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, 0 par value, 30,000,000 shares authorized; NaN issued and outstanding as of June 30, 2020 and December 31, 2019—  —  
Common stock, 0 par value, 160,000,000 shares authorized; 89,506,951 and 89,387,124 shares issued and outstanding as of June 30, 2020 and December 31, 2019, respectively1,224  1,220  
Accumulated other comprehensive loss(9) (10) 
Retained earnings1,431  1,381  
Total shareholders’ equity2,646  2,591  
Total liabilities and shareholders’ equity$8,805  $8,394  
See accompanying notes to condensed consolidated financial statements.

 September 30,
2019		 December 31,
2018
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities:   
Accounts payable$128
 $168
Liabilities from price risk management activities—current26
 55
Current portion of long-term debt50
 300
Current portion of finance lease obligation17
 —
Accrued expenses and other current liabilities293
 268
Total current liabilities514
 791
Long-term debt, net of current portion2,328
 2,178
Regulatory liabilities—noncurrent1,380
 1,355
Deferred income taxes378
 369
Unfunded status of pension and postretirement plans307
 307
Liabilities from price risk management activities—noncurrent100
 101
Asset retirement obligations268
 197
Non-qualified benefit plan liabilities100
 103
Finance lease obligations, net of current portion136
 —
Other noncurrent liabilities79
 203
Total liabilities5,590
 5,604
Commitments and contingencies (see notes)

 

Shareholders’ Equity:   
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2019 and December 31, 2018—
 —
Common stock, no par value, 160,000,000 shares authorized; 89,371,974 and 89,267,959 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively1,217
 1,212
Accumulated other comprehensive loss(7) (7)
Retained earnings1,354
 1,301
Total shareholders’ equity2,564
 2,506
Total liabilities and shareholders’ equity$8,154
 $8,110
 
See accompanying notes to condensed consolidated financial statements.



6
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
                 

Six Months Ended June 30,
20202019
Cash flows from operating activities:
Net income$120  $98  
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization212  202  
Deferred income taxes4  6  
Pension and other postretirement benefits12  12  
Allowance for equity funds used during construction(7) (5) 
Decoupling mechanism deferrals, net of amortization(8) (1) 
(Amortization) of net benefits due to Tax Reform(11) (11) 
Other non-cash income and expenses, net46  21  
Changes in working capital:
Decrease in accounts receivable, net40  63  
(Increase) in inventories(13) (17) 
(Increase)/decrease in margin deposits(9) 11  
(Decrease) in accounts payable and accrued liabilities(27) (65) 
Other working capital items, net18  16  
Other, net(21) (16) 
Net cash provided by operating activities356  314  
Cash flows from investing activities:
Capital expenditures(370) (271) 
Sales of Nuclear decommissioning trust securities4  7  
Purchases of Nuclear decommissioning trust securities(3) (5) 
Other, net(1) (2) 
Net cash used in investing activities(370) (271) 
 Nine Months Ended September 30,
 2019 2018
Cash flows from operating activities:   
Net income$153
 $163
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization305
 281
Deferred income taxes3
 2
Pension and other postretirement benefits16
 19
Allowance for equity funds used during construction(7) (8)
Decoupling mechanism deferrals, net of amortization(6) 2
(Amortization) Deferral of net benefits due to Tax Reform(16) 37
Other non-cash income and expenses, net38
 8
Changes in working capital:   
Decrease in accounts receivable and unbilled revenues50
 12
(Increase)/decrease in inventories(7) 2
Decrease in margin deposits, net4
 6
(Decrease)/increase in accounts payable and accrued liabilities(25) 17
Other working capital items, net25
 19
Other, net(31) (24)
Net cash provided by operating activities502
 536
    
Cash flows from investing activities:   
Capital expenditures(407) (401)
Sales of Nuclear decommissioning trust securities11
 11
Purchases of Nuclear decommissioning trust securities(8) (9)
Proceeds from Carty settlement—
 120
Other, net(2) 1
Net cash used in investing activities(406) (278)
    
Cash flows from financing activities:   
Proceeds from issuance of long-term debt200
 —
Payments on long-term debt(300) —
Dividends paid(99) (93)
Other(5) (4)
Net cash used in financing activities(204) (97)
(Decrease) increase in cash and cash equivalents(108) 161
Cash and cash equivalents, beginning of period119
 39
Cash and cash equivalents, end of period$11
 $200
    
Supplemental cash flow information is as follows:   
Cash paid for interest, net of amounts capitalized$73
 $72
Cash paid for income taxes21
 20
 
See accompanying notes to condensed consolidated financial statements.

7
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued
(In millions)
(Unaudited)
Six Months Ended June 30,
20202019
Cash flows from financing activities:
Proceeds from issuance of long-term debt319  200  
Payments on long-term debt(98) (300) 
Borrowings on short-term debt200  —  
Repayments of short-term debt(50) —  
Issuance of commercial paper, net—  17  
Dividends paid(69) (65) 
Other(15) (3) 
Net cash provided by (used in) financing activities287  (151) 
Increase (Decrease) in cash and cash equivalents273  (108) 
Cash and cash equivalents, beginning of period30  119  
Cash and cash equivalents, end of period$303  $11  
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized$56  $60  
Cash paid for income taxes5  20  
See accompanying notes to condensed consolidated financial statements.
8
Table of Contents

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 obtainprovide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities maintainedrecorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its4000 4,000 square mile, state-approved service area allocation, locatedencompasses 51 incorporated cities entirely within the State of Oregon, encompasses 51 incorporated cities.Oregon. As of SeptemberJune 30, 2019,2020, PGE served 892 thousand901,000 retail customers within a service area of 1.9 million residents.

Condensed Consolidated Financial Statements

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

The financial information included herein as of and for the three and ninesix months ended SeptemberJune 30, 20192020 and 20182019 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of normal recurring nature, unless otherwise noted. The financial information as of December 31, 20182019 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2018,2019, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 15, 2019,14, 2020, which should be read in conjunction with such condensed consolidated financial statements.the interim unaudited Financial Statements.

Comprehensive Income

No material change occurred in Other comprehensive income in the three and ninesix months ended SeptemberJune 30, 20192020 and 2018.2019.

Use of Estimates

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

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


89
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Recent Accounting Pronouncements

In August 2018, the FASBFinancial Accounting Standards Board (FASB) issued ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. ASU 2018-13 amends Topic 820 to add, remove, and clarify disclosure requirements related to fair value measurement disclosures. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2020, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt.

In August 2018, the FASB issued ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2020. Early adoption is permitted, including adoption in an interim period. The amendments in this update may be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PGE is in the process of evaluating potential impacts of these amendments and does not plan to early adopt.

In August 2018, the FASB issued ASUStandard Update (ASU) 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans. ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. For calendar year-end entities, theThis update will be effective for annual periods beginning on January 1, 2021. Early adoption is permitted. Asfiscal years ending after December 15, 2020. Because the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the condensed consolidated financial statements and is still evaluating whether it will early adopt.statements.

Recently Adopted Accounting Pronouncements

On January 1, 2019,2020, PGE adopted ASU 2016-02, Leases2018-13 Fair Value Measurement (Topic 842), which supersedes820): Disclosure Framework—Changes to the current lease accounting requirementsDisclosure Requirements for lessees and lessors within Topic 840, LeasesFair Value Measurement. The Company electedASU 2018-13 amends Topic 820 to add, remove, and clarify requirements related to fair value measurement disclosures. Because the practical expedient provided understandard relates only to disclosures, the implementation did not result in an impact to the results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2018-11,2018-15 LeasesIntangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. ASU 2018-15 provides guidance on implementation costs incurred in a cloud computing arrangement that is a service contract and aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. PGE applied the amendments of this ASU prospectively, and the implementation did not have a material impact on PGE’s results of operation, financial position, or cash flows.

On January 1, 2020, PGE adopted ASU 2016-13 Financial Instruments—Credit Losses (Topic 842) Targeted Improvements326): Measurement of Credit Losses on Financial Instruments. , which amended ASU 2016-02 to provide entities an optional transition practical expedient to adopt2016-13 replaces the new standardincurred loss impairment methodology in previous GAAP with a cumulative effect adjustmentmethodology that reflects expected credit losses, and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. PGE applied this ASU using a modified-retrospective approach, and as 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 sheetamounts recorded prior to January 1, 2019 and amounts are reported in accordance with historical accounting under Topic 840, while the balance sheet as of September 30, 2019 is presented under Topic 842. The Company also elected the practical expedient provided under ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842, which amended ASU 2016-02 to provide entities an optional transition practical expedient to2020 have not evaluate under Topic 842, existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. Effective January 1, 2019, PGE evaluates new or modified land easements under Topic 842.

PGE's transition to the new lease standard did not result in a material adjustment to beginning retained earnings and the Company expects the adoption ofbeen retrospectively restated. Under the new standard, PGE estimates current expected credit losses for retail sales based on an assessment of the current and forecasted probability of collection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other significant events that may impact the collectability of accounts receivable and unbilled revenues. Provisions for current expected credit losses related to retail sales, and changes to the amount of expected credit losses for existing receivables, are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for credit losses. The implementation did not have an immateriala material impact to itson PGE’s results of operationsoperation, financial position, or cash flows. To conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net 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 followingcondensed consolidated balance sheet adjustmentssheets as of JanuaryDecember 31, 2019.

On April 1, 2019: i)2020, PGE adopted ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the recognitionEffects of right-of-use assetsReference Rate Reform on Financial Reporting.ASU 2020-04 provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PGE applied the amendments of this ASU prospectively, and liabilities from operating and finance leasesthe implementation did not have a material impact on PGE’s results of $44 million pursuant to the new standard; ii) the derecognition of existing build-to-suit assets and liabilities of $131 million that were no longeroperation, financial position, or cash flows.

9
10
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

 January 1, 2019 Topic 842 Adoption Adjustments
 Increase due to existing operating and finance leases Decrease due to build-to-suit reassessment Decrease due to capital lease reassessment 
Total
Increase/(Decrease)
Assets       
Electric utility plant, net$2
 $(131) $(49) $(178)
Other noncurrent assets42
 —
 —
 42
        
Liabilities       
Accrued expenses and other current liabilities5
 —
 (2) 3
Other noncurrent liabilities39
 (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
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

NOTE 2: REVENUE RECOGNITION

Disaggregated Revenue

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

Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Retail:
Residential$223  $205  $502  $495  
Commercial140  158  299  312  
Industrial53  50  104  94  
Direct access customers12  10  23  21  
Subtotal428  423  928  922  
Alternative revenue programs, net of amortization—  (2) 9  1  
Other accrued revenues, net1  6  6  13  
Total retail revenues429  427  943  936  
Wholesale revenues*
27  16  74  53  
Other operating revenues13  17  25  44  
Total revenues$469  $460  $1,042  $1,033  
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Retail:       
Residential$218
 $224
 $713
 $699
Commercial167
 171
 479
 484
Industrial50
 55
 144
 138
Direct access customers13
 9
 34
 32
Subtotal448
 459
 1,370
 1,353
Alternative revenue programs, net of amortization4
 —
 5
 (2)
Other accrued (deferred) revenues, net(1)
4
 (11) 17
 (38)
Total retail revenues456
 448
 1,392
 1,313
Wholesale revenues(2)
72
 67
 125
 119
Other operating revenues14
 10
 58
 35
Total revenues$542
 $525
 $1,575
 $1,467

(1) Amounts for the three months ended September 30, 2019 and 2018 primarily comprised of $6 million of amortization and $11 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. Amounts for the nine months ended September 30, 2019 and 2018 primarily comprised of $17 million of amortization and $36 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA.
(2)* Wholesale revenues include $25$8 million and $29$2 million related to electricity commodity contract derivative settlements for the three months ended SeptemberJune 30, 20192020 and 2018,2019, respectively, and $38$24 million and $35$13 million respectively, for the ninesix months ended SeptemberJune 30, 2020 and 2019, and 2018.respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.

Retail Revenues

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

11
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.
Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that hashave not yet been billed to customers. This amount, which is classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.
11
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for theprograms that 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,power; hydro, solar and wind conditions,conditions; and daily and seasonal retail demand.
PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.
Other Operating Revenues
Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

Arrangements with Multiple Performance Obligations

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


12
Table of Contents

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 thatwhether inventories are recorded at the lower of average cost or net realizable value.

Accounts Receivable, Net

Accounts receivable, net includes $74 million and $86 million of unbilled revenues as of June 30, 2020 and December 31, 2019, respectively. Accounts receivable, net is net of an allowance for credit losses of $12 million as of June 30, 2020. The following summarizes activity in the allowance for credit losses (in millions):
 Three Months Ended June 30, 2020Six Months Ended June 30, 2020
Balance as of beginning of period$6  $5  
Increase in provision7  9  
Amounts written off(3) (6) 
Recoveries2  4  
Balance as of end of period$12  $12  
In connection with the adoption of ASU 2016-13 and to conform with 2020 presentation, PGE reclassified $86 million of Unbilled revenues to Accounts receivable, net on the condensed consolidated balance sheets as of December 31, 2019.

Other Current Assets

Other current assets consist of the following (in millions):
June 30, 2020December 31, 2019
Prepaid expenses$37  $63  
Assets from price risk management activities46  25  
Margin deposits25  16  
Other current assets$108  $104  
 September 30, 2019 December 31, 2018
Prepaid expenses$28
 $54
Assets from price risk management activities14
 20
Margin deposits12
 16
Other current assets$54
 $90


Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):
June 30, 2020December 31, 2019
Electric utility plant$11,163  $10,928  
Construction work-in-progress376  328  
Total cost11,539  11,256  
Less: accumulated depreciation and amortization(4,238) (4,095) 
Electric utility plant, net$7,301  $7,161  
13
Table of Contents

 September 30, 2019 December 31, 2018
Electric utility plant$10,778
 $10,344
Construction work-in-progress258
 346
Total cost11,036
 10,690
Less: accumulated depreciation and amortization(4,022) (3,803)
Electric utility plant, net$7,014
 $6,887
PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $350$397 million and $302$366 million as of SeptemberJune 30, 20192020 and December 31, 2018,2019, respectively. Amortization expense related to intangible assets was $16$31 million and $49$33 million for the three and ninesix months ended SeptemberJune 30, 2020 and 2019, respectively, and $16 million and $43$17 million for the three and nine months ended SeptemberJune 30, 2018,2020 and 2019, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

13
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):
 September 30, 2019 December 31, 2018
 Current Noncurrent Current Noncurrent
Regulatory assets:       
Price risk management$12
 $96
 $32
 $99
Pension and other postretirement plans—
 218
 —
 222
Debt issuance costs—
 18
 —
 16
Trojan decommissioning activities—
 93
 —
 26
Other14
 58
 29
 38
Total regulatory assets$26
 $483
 $61
 $401
Regulatory liabilities:       
Asset retirement removal costs$—
 $1,011
 $—
 $979
Deferred income taxes—
 262
 —
 267
Asset retirement obligations—
 54
 —
 53
Tax Reform Deferral(1)
23
 6
 23
 22
Other17
 47
 13
 34
Total regulatory liabilities$40
(2) 
$1,380
 $36
(2) 
$1,355

(1) Related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest.
June 30, 2020December 31, 2019
CurrentNoncurrentCurrentNoncurrent
Regulatory assets:
Price risk management$—  $135  $—  $95  
Pension and other postretirement plans—  204  —  213  
Debt issuance costs—  27  —  26  
Trojan decommissioning activities—  94  —  94  
Other12  66  17  55  
Total regulatory assets$12  $526  $17  $483  
Regulatory liabilities:
Asset retirement removal costs$—  $996  $—  $1,021  
Deferred income taxes—  256  —  260  
Asset retirement obligations—  55  —  54  
Tax Reform deferral12  —  23  —  
Other28  55  21  42  
Total regulatory liabilities$40  
*
$1,362  $44  
*
$1,377  
(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):
June 30, 2020December 31, 2019
Accrued employee compensation and benefits$63  $74  
Accrued taxes payable31  33  
Accrued interest payable27  25  
Accrued dividends payable36  36  
Regulatory liabilities—current40  44  
Other92  103  
Total accrued expenses and other current liabilities$289  $315  
 September 30, 2019 December 31, 2018
Accrued employee compensation and benefits$63
 $66
Accrued taxes payable45
 34
Accrued interest payable39
 27
Accrued dividends payable35
 34
Regulatory liabilities—current40
 36
Other71
 71
Total accrued expenses and other current liabilities$293
 $268



14
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Asset Retirement Obligations

Asset retirement obligations (AROs) consist of the following (in millions):
 September 30, 2019 December 31, 2018
Trojan decommissioning activities$137
 $68
Utility plant114
 112
Non-utility property17
 17
Asset retirement obligations$268
 $197


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

Credit Facilities

As of December 31, 2018,June 30, 2020, PGE had a $500 million revolving credit facility scheduled to terminateexpire in November 2021. On January 16, 2019, PGE executed an amendment2023. The Company has the ability to expand the revolving 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. $600 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for
14
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of SeptemberJune 30, 2019,2020, PGE was in compliance with this covenant with a 50.2%54.4% debt-to-total capital ratio.

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

PGE typically classifies 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 SeptemberJune 30, 2019,2020, PGE had 0 borrowings outstanding or commercial paper issued.outstanding. As a result, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total capacity of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $6046 million were outstanding as of June 30, 2020. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

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

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 7, 2022.

Long-term Debt

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

On April 27, 2020, PGE issued $200 million of 3.15% Series First Mortgage Bonds (FMBs) due in 2030.
15
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

Long-term Debt

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

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

Defined Benefit Retirement Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Service cost$4
 $5
 $12
 $15
Interest cost*8
 8
 25
 24
Expected return on plan assets*(10) (10) (30) (31)
Amortization of net actuarial loss*3
 4
 8
 12
Net periodic benefit cost$5
 $7
 $15
 $20


Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Service cost$4  $4  $8  $8  
Interest cost*8  9  16  17  
Expected return on plan assets*(11) (10) (22) (20) 
Amortization of net actuarial loss*4  2  8  5  
Net periodic benefit cost$5  $5  $10  $10  
* The expense portion of non-service cost components are included in Miscellaneous income (loss), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

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


NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of SeptemberJune 30, 20192020 and December 31, 2018.2019. PGE then classifies these financial assets and liabilities based on a fair

16
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

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

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

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were 0 significant transfers between levels during the three and nine months ended September 30, 2019 and 2018, except those presented in this note.


17
16
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):
As of June 30, 2020
Level 1Level 2Level 3
Other(2)
Total
Assets:
Cash equivalents$293  $—  $—  $—  $293  
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government7  12  —  —  19  
Corporate credit—  15  —  —  15  
Money market funds measured at NAV (2)
—  —  —  13  13  
Non-qualified benefit plan trust: (3)
Money market funds1  —  —  —  1  
Equity securities6  —  —  —  6  
Debt securities—domestic government1  —  —  —  1  
Price risk management activities: (1) (4)
Electricity—  28  —  —  28  
Natural gas—  25  3  —  28  
$308  $80  $3  $13  $404  
Liabilities:
Price risk management activities: (1) (4)
Electricity$—  $19  $154  $—  $173  
Natural gas—  12  —  —  12  
$—  $31  $154  $—  $185  
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.
17
 As of September 30, 2019
 Level 1 Level 2 Level 3 
Other(2)
 Total
Assets:         
Cash equivalents$—
 $—
 $—
 $—
 $—
Nuclear decommissioning trust: (1)
         
Debt securities:         
Domestic government7
 15
 —
 —
 22
Corporate credit—
 12
 —
 —
 12
Money market funds measured at NAV (2)
—
 —
 —
 12
 12
Non-qualified benefit plan trust: (3)
         
Money market funds2
 —
 —
 —
 2
Equity securities6
 —
 —
 —
 6
Debt securities—domestic government1
 —
 —
 —
 1
Price risk management activities: (1) (4)
         
Electricity—
 6
 1
 —
 7
Natural gas—
 10
 1
 —
 11
 $16
 $43
 $2
 $12
 $73
Liabilities:         
Price risk management activities: (1) (4)
         
Electricity$—
 $5
 $99
 $—
 $104
Natural gas—
 18
 4
 —
 22
 $—
 $23
 $103
 $—
 $126
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $28 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.


18
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

As of December 31, 2018As of December 31, 2019
Level 1 Level 2 Level 3 
Other (2)
 TotalLevel 1Level 2Level 3
Other (2)
Total
Assets:         Assets:
Cash equivalents$112
 $—
 $—
 $—
 $112
Cash equivalents$26  $—  $—  $—  $26  
Nuclear decommissioning trust: (1)
         
Nuclear decommissioning trust: (1)
Debt securities:         Debt securities:
Domestic government7
 18
 —
 —
 25
Domestic government8  16  —  —  24  
Corporate credit—
 10
 —
 —
 10
Corporate credit—  9  —  —  9  
Money market funds measured at NAV (2)
—
 —
 —
 7
 7
Money market funds measured at NAV (2)
—  —  —  13  13  
Non-qualified benefit plan trust: (3)
         
Non-qualified benefit plan trust: (3)
Debt securities—domestic governmentDebt securities—domestic government1  —  —  —  1  
Money market funds2
 —
 —
 —
 2
Money market funds1  —  —  —  1  
Equity securities6
 —
 —
 —
 6
Equity securities7  —  —  —  7  
Debt securities—domestic government1
 —
 —
 —
 1
Price risk management activities: (1) (4)
         
Price risk management activities: (1) (4)
Electricity—
 9
 3
 —
 12
Electricity—  9  7  —  16  
Natural gas—
 8
 —
 —
 8
Natural gas—  21  1  —  22  
$128
 $45
 $3
 $7
 $183
$43  $55  $8  $13  $119  
Liabilities:         Liabilities:
Interest rate swap derivatives$—
 $4
 $—
 $—
 $4
Price risk management activities: (1) (4)
         
Price risk management activities: (1) (4)
Electricity—
 10
 84
 —
 94
Electricity—  14  105  —  119  
Natural gas—
 51
 7
 —
 58
Natural gas—  12  —  —  12  
$—
 $65
 $91
 $—
 $156
$—  $26  $105  $—  $131  
 
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $27 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.
(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(3)Excludes insurance policies of $29 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.

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

Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:
 
Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value

19
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.
18
Table of Contents

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

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

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

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

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

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


20
19
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:
Fair ValueValuation TechniqueSignificant Unobservable InputPrice per Unit
Commodity ContractsAssetsLiabilitiesLowHighWeighted Average
(in millions)
As of June 30, 2020
Electricity physical forwards$—  $147  Discounted cash flowElectricity forward price (per MWh)$2.69  $38.84  $29.51  
Natural gas financial swaps3  —  Discounted cash flowNatural gas forward price (per Decatherm)1.44  3.91  2.12  
Electricity financial futures—  7  Discounted cash flowElectricity forward price (per MWh)13.25  51.03  36.29  
$3  $154  
As of December 31, 2019
Electricity physical forwards$—  $104  Discounted cash flowElectricity forward price (per MWh)$12.53  $59.00  $36.92  
Natural gas financial swaps1  ���  Discounted cash flowNatural gas forward price (per Decatherm)1.39  3.73  1.90  
Electricity financial futures7  1  Discounted cash flowElectricity forward price (per MWh)10.57  66.32  45.11  
$8  $105  
  Fair Value Valuation Technique Significant Unobservable Input Price per Unit
Commodity Contracts Assets Liabilities   Low High Weighted Average
  (in millions)          
As of September 30, 2019              
Electricity physical forwards $—
 $96
 Discounted cash flow Electricity forward price (per MWh) $11.57
 $64.41
 $42.98
Natural gas financial swaps 1
 4
 Discounted cash flow Natural gas forward price (per Decatherm) 1.23
 3.74
 1.69
Electricity financial futures 1
 3
 Discounted cash flow Electricity forward price (per MWh) 15.50
 53.97
 36.90
  $2
 $103
          
As of December 31, 2018              
Electricity physical forwards $3
 $84
 Discounted cash flow Electricity forward price (per MWh) $14.60
 $69.00
 $45.00
Natural gas financial swaps —
 7
 Discounted cash flow Natural gas forward price (per Decatherm) 0.95
 4.64
 1.82
  $3
 $91
          


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

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

Significant Unobservable InputPositionChange to InputImpact on Fair Value
Market priceBuyIncrease (decrease)Gain (loss)
Market priceSellIncrease (decrease)Loss (gain)
Significant Unobservable InputPositionChange to InputImpact on Fair Value Measurement
Market priceBuyIncrease (decrease)Gain (loss)
Market priceSellIncrease (decrease)Loss (gain)


21
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):
 Three Months Ended September 30, Nine Months Ended September 30,
 2019
2018 2019 2018
Balance as of the beginning of the period$72
 $129
 $88
 $139
Net realized and unrealized (gains)/losses*
30
 (2) 14
 (10)
Transfers out of Level 3 to Level 2(1) (2) (1) (4)
Balance as of the end of the period$101
 $125
 $101
 $125
20
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Balance as of the beginning of the period$134  $70  $97  $88  
Net realized and unrealized losses/(gains)*
17  3  56  (16) 
Transfers from Level 3 to Level 2—  (1) (2) —  
Balance as of the end of the period$151  $72  $151  $72  
* Both realized and unrealized losses/(gains)/losses,, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three and nine months ended September 30, 2019 and 2018, there were0 transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and out of Level 3 at the end of the reporting period for all of its derivative instruments.

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

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

As of SeptemberJune 30, 2019,2020, the carrying amount of PGE’s long-term debt was $2,378$2,816 million, net of $10$13 million of unamortized debt expense, and its estimated aggregate fair value was $2,754$3,508 million. As of December 31, 2018,2019, the carrying amount of PGE’s long-term debt was $2,478$2,597 million, net of $10$11 million of unamortized debt expense, and its estimated aggregate fair value was $2,760$3,039 million.

NOTE 5: RISK MANAGEMENT

Price Risk Management

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

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

22
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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.

21
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):
 September 30, 2019 December 31, 2018
Current assets:   
Commodity contracts:   
Electricity$6
 $11
Natural gas8
 7
Total current derivative assets(1)
14
 18
Noncurrent assets:   
Commodity contracts:   
Electricity1
 1
Natural gas3
 1
Total noncurrent derivative assets(1)
4
 2
Total derivative assets(2)
$18
 $20
Current liabilities:   
Commodity contracts:   
Electricity$12
 $16
Natural gas14
 35
Total current derivative liabilities26
 51
Noncurrent liabilities:   
Commodity contracts:   
Electricity92
 78
Natural gas8
 23
Total noncurrent derivative liabilities100
 101
Total derivative liabilities(2)
$126
 $152

June 30, 2020December 31, 2019
Current assets:
Commodity contracts:
Electricity$28  $9  
Natural gas18  16  
Total current derivative assets(1)
46  25  
Noncurrent assets:
Commodity contracts:
Electricity—  7  
Natural gas10  6  
Total noncurrent derivative assets(1)
10  13  
Total derivative assets(2)
$56  $38  
Current liabilities:
Commodity contracts:
Electricity$30  $14  
Natural gas10  9  
Total current derivative liabilities40  23  
Noncurrent liabilities:
Commodity contracts:
Electricity143  105  
Natural gas2  3  
Total noncurrent derivative liabilities145  108  
Total derivative liabilities(2)
$185  $131  
(1) Total current derivative assets isare included in Other current assets, and Total noncurrent derivative assets isare included in Other noncurrent assets on the condensed consolidated balance sheets.
(2) As of SeptemberJune 30, 20192020 and December 31, 2018,2019, no derivative assets or liabilities were designated as hedging instruments.



23
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(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):
 September 30, 2019 December 31, 2018
Commodity contracts:     
Electricity6
MWhs 5
MWhs
Natural gas140
Decatherms 123
Decatherms
Foreign currency$21
Canadian $18
Canadian

June 30, 2020December 31, 2019
Commodity contracts:
Electricity8  MWhs6  MWhs
Natural gas147  Decatherms145  Decatherms
Foreign currency$21  Canadian$23  Canadian

PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of SeptemberJune 30, 2019, and December 31, 2018,2020, gross amounts included as Price risk management liabilities subject to
22
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
master netting agreements werewas $2 million, and $88 million, respectively,comprised solely of natural gas contracts for which PGE posted no collateral as of September 30, 2019 and $11 million ascollateral. As of December 31, 2018, which consisted entirely of letters of credit. As of September 30, 2019, of the gross amounts recognized, NaNwas 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.PGE had no material master netting arrangements.

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Commodity contracts:       
Electricity$36
 $(3) $18
 $(5)
Natural Gas(9) (3) (13) 11
Foreign currency exchange—
 —
 —
 1

Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Commodity contracts:
Electricity$15  $6  $47  $(18) 
Natural Gas(13) 21  (4) (4) 
Foreign currency exchange—  —  1  —  
Net unrealized and certain net realized losses losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended SeptemberJune 30, 2020 and 2019, net gains of $1 million and 2018, netlosses of $24$30 million, respectively, have been offset. Net losses of $41 million and net gains of $8 million, respectively, have been offset. Net losses of $5 million and net gains of $2$19 million have been offset for the ninesix months ended SeptemberJune 30, 20192020 and 2018,2019, respectively.


24
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss loss/(gain) recorded as of SeptemberJune 30, 20192020 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):
 2019 2020 2021 2022 2023 Thereafter Total
Commodity contracts:             
Electricity$(3) $11
 $9
 $7
 $7
 $66
 $97
Natural gas2
 5
 4
 —
 —
 —
 11
Net unrealized loss$(1) $16
 $13
 $7
 $7
 $66
 $108


20202021202220232024ThereafterTotal
Commodity contracts:
Electricity$(6) $16  $8  $8  $8  $111  $145  
Natural gas(1) (13) (2) —  —  —  (16) 
Net unrealized loss$(7) $3  $6  $8  $8  $111  $129  
PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of SeptemberJune 30, 20192020 was $118$161 million, for which PGE has posted $21$6 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at SeptemberJune 30, 2019,2020, the cash requirement to either post as collateral or settle the instruments immediately would have been $109$151 million. As of SeptemberJune 30, 2019,2020, PGE had0 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:
23
Table of Contents
 September 30, 2019 December 31, 2018
Assets from price risk management activities:   
Counterparty A35% 42%
Counterparty B—
 15
Counterparty C17
 5
Counterparty D11
 9
 63% 71%
Liabilities from price risk management activities:   
Counterparty E76% 56%


PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
June 30, 2020December 31, 2019
Assets from price risk management activities:
Counterparty A37 %35 %
Counterparty B11  13  
Counterparty C11  11  
Counterparty D9  11  
68 %70 %
Liabilities from price risk management activities:
Counterparty E79 %79 %
See Note 4, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

Interest Rate Risk

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

25
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

As of December 31, 2018, the fair value of the interest rate swaps was a $4 million liability, which was recorded in Liabilities from price risk management activities - current on the Company’s condensed consolidated balance sheets. The swaps settled at a $5 million loss in January 2019, which has been recorded in Regulatory assets - noncurrent on the condensed consolidated balance sheets. As of September 30, 2019, the Company had0 outstanding interest rate swaps.

NOTE 6: EARNINGS PER SHARE

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

For the three and ninesix months ended SeptemberJune 30, 2019,2020, unvested performance-based restricted stock units and related dividend equivalent rights of 265303 thousandshares were excluded from the dilutive calculation because the performance goals had not been met, with 229267 thousand shares excluded for the three and ninesix months ended SeptemberJune 30, 2018.2019.

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Weighted-average common shares outstanding—basic89,489  89,357  89,459  89,333  
Dilutive effect of potential common shares136  204  143  204  
Weighted-average common shares outstanding—diluted89,625  89,561  89,602  89,537  
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Weighted-average common shares outstanding—basic89,372
 89,239
 89,346
 89,205
Dilutive effect of potential common shares222
 —
 209
 —
Weighted-average common shares outstanding—diluted89,594
 89,239
 89,555
 89,205


24

26
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

NOTE 7: SHAREHOLDERS’ EQUITY

The activity in equity during the three and nine-monthsix-month periods ended SeptemberJune 30, 20192020 and 20182019 was as follows (dollars in millions, except per share amounts):
Common StockAccumulated
Other
Comprehensive
Loss		Retained
Earnings
SharesAmountTotal
Balances as of December 31, 201989,387,124  $1,220  $(10) $1,381  $2,591  
Issuances of shares pursuant to equity-based plans77,397  —  —  —  —  
Other comprehensive income—  —  1  —  1  
Dividends declared ($0.3850 per share)—  —  —  (35) (35) 
Net income—  —  —  81  81  
Balances as of March 31, 202089,464,521  1,220  (9) 1,427  2,638  
Issuances of shares pursuant to equity-based plans42,430  1  —  —  1  
Stock-based compensation—  3  —  —  3  
Dividends declared ($0.3850 per share)—  —  —  (35) (35) 
Net income—  —  —  39  39  
Balances as of June 30, 202089,506,951  $1,224  $(9) $1,431  $2,646  
Balances as of December 31, 201889,267,959  $1,212  $(7) $1,301  $2,506  
Issuances of shares pursuant to equity-based plans88,352  —  —  —  —  
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, 201989,356,311  1,212  (8) 1,344  2,548  
Issuances of shares pursuant to equity-based plans15,249  1  —  —  1  
Stock-based compensation—  2  —  —  2  
Other comprehensive income—  —  1  —  1  
Dividends declared ($0.3850 per share)—  —  —  (35) (35) 
Net income—  —  —  25  25  
Balances as of June 30, 201989,371,560  $1,215  $(7) $1,334  $2,542  
 Common Stock 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
  
     
 Shares Amount   Total
Balances as of December 31, 201889,267,959
 $1,212
 $(7) $1,301
 $2,506
Issuances of shares pursuant to equity-based plans88,352
 —
 —
 —
 —
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, 201989,356,311
 $1,212
 $(8) $1,344
 $2,548
Issuances of shares pursuant to equity-based plans15,249
 1
 —
 —
 1
Stock-based compensation—
 2
 —
 —
 2
Other comprehensive income—
 —
 1
 —
 1
Dividends declared ($0.3850 per share)—
 —
 —
 (35) (35)
Net income—
 —
 —
 25
 25
Balances as of June 30, 201989,371,560
 $1,215
 $(7) $1,334
 $2,542
Issuances of shares pursuant to equity-based plans414
 —
 —
 —
 —
Stock-based compensation—
 2
 —
 —
 2
Dividends declared ($0.3850 per share)—
 —
 —
 (35) (35)
Net income—
 —
 —
 55
 55
Balances as of September 30, 201989,371,974
 $1,217
 $(7) $1,354
 $2,564


25

27
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

 Common Stock 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
  
     
 Shares Amount   Total
Balances as of December 31, 201789,114,265
 $1,207
 $(8) $1,217
 $2,416
Issuances of shares pursuant to equity-based plans99,854
 —
 —
 —
 —
Stock-based compensation—
 (1) —
 —
 (1)
Dividends declared ($0.3400 per share)—
 —
 —
 (30) (30)
Net income—
 —
 —
 64
 64
Balances as of March 31, 201889,214,119
 $1,206
 $(8) $1,251
 $2,449
Issuances of shares pursuant to equity-based plans24,087
 —
 —
 —
 —
Stock-based compensation—
 2
 —
 —
 2
Dividends declared ($0.3625 per share)—
 —
 —
 (32) (32)
Net income—
 —
 —
 46
 46
Balances as of June 30, 201889,238,206
 $1,208
 $(8) $1,265
 $2,465
Issuances of shares pursuant to equity-based plans6,453
 —
 —
 —
 —
Stock-based compensation—
 1
 —
 —
 1
Dividends declared ($0.3625 per share)—
 —
 —
 (33) (33)
Net income—
 —
 —
 53
 53
Balances as of September 30, 201889,244,659
 $1,209
 $(8) $1,285
 $2,486


NOTE 8: CONTINGENCIES

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

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

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


28
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(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 the nature of the underlying event.

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

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE has been included among more than 100 Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.

TheA Portland Harbor site remedial investigation had beenwas 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.
26
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in January 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of the Portland Harbor, site, which hadhas an undiscounted estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.1 billion.costs. Remediation construction costs were estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost.

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of the Portland Harbor Superfund site have improved substantially over the past ten years. In response, the EPA indicated that while it acceptedwould use the data and would use it to inform implementation of the ROD, it did not agree that the data collected, orEPA’s conclusions remained materially unchanged. With the analysis offered, supported manycompletion of the conclusions reachedpre-remedial design sampling, Portland Harbor is now in the sampling update.remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs have entered into consent agreements, or are in good-faith discussion with the EPA, to perform remedial design, and if the EPA deems necessary, it has communicated it would issue Special Notice Letters to enforce action of remedial design.

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

29
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

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

The impact of such costs related to EPA and NRD liabilities on the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account mechanism (PHERA) mechanism.. As approved by the OPUC in 2017,
27
Table of Contents

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

Trojan Investment Recovery Class Actions

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

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


30
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

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

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

In November 2019, the Court of Appeals decision remains pending.

PGE believesissued an opinion that the 2014 OSC decision andaffirmed the Circuit Court decisionsdismissal. In December 2019, the plaintiffs filed a motion for reconsideration, which the Court of Appeals denied on February 4, 2020.

On April 7, 2020 the Plaintiffs filed a petition with the OSC requesting review and reversal of the Court of Appeals opinion. On July 16, 2020, the OSC issued an order that followed have reduceddenied the risk of any loss to the Company beyond the amounts previously recorded and refunds discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.petition for review.

Deschutes River Alliance Clean Water Act Claims

In 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had violated certain conditions contained in PGE’s Water Quality Certification for the Pelton 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.
28
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

31
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


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

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

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

Other Matters

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

NOTE 9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas 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 SeptemberJune 30, 2019,2020, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.


32
29
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

NOTE 10: INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended June 30,Six Months Ended June 30,
2019 2018 2019 20182020201920202019
Federal statutory tax rate21.0 % 21.0 % 21.0 % 21.0 %Federal statutory tax rate21.0 %21.0 %21.0 %21.0 %
Federal tax credits*
(14.8) (12.3) (13.8) (15.8)
Federal tax credits*
(14.4) (15.1) (12.0) (13.3) 
State and local taxes, net of federal tax benefit6.5
 6.5
 6.5
 6.5
State and local taxes, net of federal tax benefit10.9  6.5  8.5  6.5  
Flow through depreciation and cost basis differences1.0
 (0.1) 1.2
 (2.3)
Flow-through depreciation and cost basis differencesFlow-through depreciation and cost basis differences(2.6) 0.4  0.3  1.4  
Amortization of excess deferred income tax(3.9) —
 (3.5) —
Amortization of excess deferred income tax(2.5) (2.7) (2.1) (3.2) 
Other—
 (0.6) 0.2
 3.0
Other(1.0) 0.6  0.4  0.1  
Effective tax rate9.8 % 14.5 % 11.6 % 12.4 %Effective tax rate11.4 %10.7 %16.1 %12.5 %
       
* Federal tax credits consistsconsist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2024.

Carryforwards

Federal tax credit carryforwards as of SeptemberJune 30, 20192020 and December 31, 20182019 were $55 million and $52 million, respectively.64 million. These credits consist of PTCs, which will expire at various dates through 2039.2040. PGE believes that it is more likely than not that its deferred income tax assets as of SeptemberJune 30, 20192020 will be realized; accordingly, 0 valuation allowance has been recorded. As of SeptemberJune 30, 2019,2020, and December 31, 2018,2019, PGE had 0no material unrecognized tax benefits.

NOTE 11: LEASES

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

Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments will be deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.


33
30
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

The components of lease cost were as follows (in millions):
 Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019
    
Operating lease cost$3
 $6
    
Finance lease cost:   
Amortization of right-of-use assets$1
 $2
Interest on lease liabilities3
 4
Total finance lease cost$4
 $6
    
Variable lease cost$4
 $15


Supplemental information related to amounts and presentation of leases in the condensed consolidated balance sheets is presented below (in millions):
 Balance Sheet ClassificationSeptember 30, 2019
Operating Leases:  
Operating lease right-of-use assetsOther noncurrent assets$52
   
Current liabilitiesAccrued expenses and other current liabilities8
Noncurrent liabilitiesOther noncurrent liabilities44
Total operating lease liabilities $52
   
Finance Leases:  
Finance lease right-of-use assetsElectric utility plant, net$152
   
Current liabilitiesCurrent portion of finance lease obligations17
Noncurrent liabilitiesFinance lease obligations, net of current portion136
Total finance lease liabilities $153



34
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

Lease term and discount rates were as follows:
September 30, 2019
Weighted Average Remaining Lease Term
Operating leases24 years
Finance leases29 years
Weighted Average Discount Rate
Operating leases3.5%
Finance leases7.3%


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

As of September 30, 2019, maturities of lease liabilities were as follows (in millions):
 Operating Leases Finance Leases
    
2019$2
 $4
20208
 16
20218
 16
20228
 16
20238
 14
Thereafter53
 249
Total lease payments87
 315
Less imputed interest(35) (162)
Total$52
 $153


Supplemental cash flow information related to leases was as follows (in millions):
 Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities: 
Operating cash flows from operating leases$5
Operating cash flows from finance leases3
Financing cash flows from finance leases2
  
Right-of-use assets obtained in leasing arrangements: 
Operating leases$56
Finance leases154



35
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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
20206
 14
 5
20216
 13
 5
20226
 13
 6
20235
 13
 7
Thereafter67
 225
 97
Total minimum lease payments96
 $289
 $124
Less imputed interest(47)    
Present value of net minimum lease payments49
    
Less current portion(2)    
Noncurrent portion$47
    


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

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

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


36
Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

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

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

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, future loads, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s forward-looking statementsexpectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that thePGE’s expectations, beliefs, or projections contained in such forward-looking statements will be achieved or accomplished.

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

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

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

•changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators;
•the outcomesoutcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements;

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

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

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


37
Table of Contents•


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

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

31
Table of Contents
•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 whichthat could require PGE to post additional collateral or issue additional letters of credit or post additional cash as collateral with counterparties pursuant to power and natural gas purchase agreements;

•changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs;

•capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;

•future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;

•changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;

•the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;
•changes in residential, commercial, andor industrial customer growth, and inor demographic patterns, in PGE’s service territory;

ineffective execution•the effectiveness 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•cybersecurity attacks, data security breaches, or other malicious acts that may cause damage to the Company’s generation, transmission, andor 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;management, and the ability to recruit and retain appropriate talent;

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

•natural disasters and other risks, such as pandemic, earthquake, flood, drought, lightning, wind, and fire;
•the impact of widespread health developments, including the recent global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities), which could materially and adversely affect, among other things, demand for electric services, customers’ ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;
•changes in financial or regulatory accounting principles or policies imposed by governing bodies; and

•acts of war or terrorism.

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


38
32
Table of Contents


OVERVIEW
Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. ThisThe 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 asin the state of Oregon. In addition, the Company participates in wholesale purchasemarkets by purchasing and sale ofselling electricity and natural gas in orderan effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

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

•Reduce greenhouse gas emissions associated with serving its retail load by more than 80 percent below 2010 levels by 2050;
•Electrify sectors of the economy, including transportation and buildings, that are also transforming to reduce greenhouse gas emissions; and
•Perform as a business, driving improvements to work efficiency, safety, and systems and equipment reliability, all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on four pillars: i) delivering exceptional customer service; ii) investingaverage.

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

Retail loads—The economic impacts of the COVID-19 pandemic and the Governor’s initial stay-at-home order and subsequent phased reopening approach has not allowed all businesses to reopen, or has allowed reopening only at reduced capacity to meet requirements for social distancing. The slowdown in certain sectors of the economy has resulted in changes in retail load patterns. After adjusting for the effects of weather, retail energy deliveries for the three months ended June 30, 2020 decreased 3% compared to the same period of 2019. The change was driven by an increase of 7% in residential deliveries as a larger percent of the population is spending more time at home, a 16% decrease in commercial deliveries as many business have faced temporary or permanent closures, and a 3% increase in industrial energy deliveries. Based on these trends in retail load patterns the Company currently projects that retail energy deliveries will remain flat compared to 2019 weather-adjusted levels, however changes in deliveries across customer classes may impact retail revenues. See “Customers and Demand” in this Overview
33
Table of Contents
section and “Revenues” of the Results of Operations section for more information related to COVID-19 impacts on retail loads.

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

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

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

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

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

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

Legislative and regulatory developments—The Company has analyzed available relief for the economic effects of COVID-19 under the following:
34
Table of Contents
•FERC Waiver—On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative AFDC calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction. PGE has adopted the waiver and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC for the three and six months ended June 30, 2020.
•Coronavirus Aid, Relief, and Economic Security (CARES) Act—On March 27, 2020, the U.S. Government enacted the CARES Act, which provides approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 pandemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. The Company does not expect direct material benefits from the CARES Act.
•COVID-19 Deferral—PGE filed an application for deferral of certain incremental costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. This application seeks to recover costs and lost revenue (including customer receivable write-offs and other incremental costs or lost revenue arising from the COVID-19 pandemic) incurred from the date of the application through at least the end of 2020. PGE will defer such costs if they are deemed probable of recovery. Until such determination is made, any incremental expenses will be recognized in the results of operations. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test.
Reduce greenhouse gas emissions—PGE partners with customers and local and state governments to advance a clean energy future;future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help the state meet its greenhouse gas reduction goals.

PGE’s framework for achieving a clean energy future is informed and enabled by: i) customer renewable energy programs; ii) carbon legislation and administrative actions; iii) building a smarter, more resilient grid;the resource planning process; and iv) pursuing excellence in its work.

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

PGE’s customers continue to express a commitment to purchasing clean energy, as over 215,000228,000 customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions

There has been a growing trend of business customers with goals to achievebe served by 100 percent clean electricity. In addition, at least four municipalities in PGE’s service territory have climate action plans and renewableresolutions with 100 percent clean or net-zero carbon electricity bygoals between 2030 and 2035 and 100 percent clean or net-zero carbon economy-wide clean and renewable energy goals by 2050. Other jurisdictions in PGE’s service area continue to consider similar goals.

In response, the Company has implemented a new customer product option, the Green Future Impact program which allowsas a tool to help customers reach their goals. The first phase allowed for 100 megawatts (MW)up to 160 MW of PGE-provided power purchase agreements for renewable resources and up to 200140 MW of customer-provided renewable resources. ApprovedPGE has proposed a second phase to increase the cap from 300 MW to 500 MW to allow more customers to participate in the program. The Company is currently working through the regulatory review process for the second phase, which is expected to conclude by the OPUC in the first quarter 2019, theend of 2020.

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

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

Legislative developments that have recently shaped the regulatory framework include Senate Bill 978 (SB 978), which passed the Oregon legislature in 2017. SB 978 directed the OPUC to investigate and report to the Oregon legislature how developing industry trends, technology, and policy drivers in the electricity sector might impact the existing regulatory system and incentives. The September 2018 report outlined the OPUC’s commitment to:
explore performance-based ratemaking and other regulatory tools to align utility incentives with customer goals, industry trends, and statewide goals;
▪cooperate with other states to support and explore development of an organized, regional market;
▪develop a strategy for low income and environmental justice groups’ engagement and inclusion in OPUC processes that will carry forward beyond the SB 978 proceeding; and
▪improve the OPUC’s regulatory tools to value system costs and benefits, which enables customer choice and a strong utility system.

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

39
Table of Contents


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

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

Carbon Legislation and Administrative Actions—Oregon’s Clean Electricity and Coal Transition Plan (OCEP), enacted inIn 2016, Oregon Senate Bill (SB) 1547 set a benchmark for how muchpercentages of electricity that must come from renewable sources like wind and solar (50 percent by 2040) and requires the elimination of coal from Oregon
35
Table of Contents
utility customers’ energy supply no later than 2030.2030 (subject to an exception that allowed extension of this date until 2035 for PGE’s output from Colstrip).

Provisions of the law include:
•An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
•A limitation on the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and
•An allowance for energy storage costs related to renewable energy in an electric company’s Renewable Adjustment Clause (RAC) filings.

In response to the OCEP,SB 1547, the Company filed a tariff request in October 2016 to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030.2030, which the OPUC approved. In late June 2019,January 2020, the owners of Colstrip Units 1 and 2 announced that they would permanently closeretired those two units at the end of the current year.units. Although PGE has no direct ownership interest in those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which shareutilize certain common facilities with Units 1 and 2.

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

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

The Company had previously announced, and continues on schedule with plans to cease coal-fired operation at its Boardman generating plant atby the end of 2020.

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

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

legislative sessions.

Among other things, the Executive Order:
•Modifies the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050.
36
Table of Contents
•Directs state agencies to integrate climate change and the State’s GHG reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law.
•Directs the OPUC to—
◦determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon’s reduction goals;
◦encourage electric companies to support transportation electrification infrastructure that supports GHG reductions and the SB 1044 zero emission vehicle goals; and
◦prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy.
•Directs the Oregon Department of Environmental Quality (DEQ) to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas.
•More than doubles the reduction goals of the state’s Clean Fuels Program and extends the program, from the current rule that requires a 10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

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

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

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

PGE will own 100 MW of the wind resource with an investment of approximately $160million. Subsidiaries of NextEra Energy Resources, LLC will own the balance of the 300 MW wind resource, along with the solar and battery components, and sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to purchase the underlying assets of the power purchase agreementagreements on the 12thtwelfth anniversary of the commercial operation date of the wind facility. As of June 30, 2020, the Company has recorded $56 million, including the allowance for funds used during construction (AFDC), in construction work-in-progress (CWIP) related to Wheatridge.

40
Table of Contents



The wind component of the facility is expected to be operational and placed in-service by December 2020 and qualify for federal production tax credits (PTCs) at the 100 percent level. Construction of the solar and battery components is planned for 2021 and is also expected to qualify for federal investment tax credits, which will help reducecredits. To date, PGE has not experienced any supply chain disruptions due to the costCOVID-19 pandemic related to the construction of Wheatridge, and the
37
Table of Contents
project is proceeding as planned. PGE is working closely with the project and thus reduce costscontractor to PGE’s customers.actively monitor for supply chain issues. See “COVID-19 Impacts” within this “Overview” section for further information on COVID-19.

In July 2019, PGE submitted its 2019 Integrated Resource Plan (2019 IRP) to the OPUC. The initial plan and modifications proposed plan setsby PGE within the docket (LC 73) set forth the following actions the Company wouldproposed to undertake over the next four years to acquire the resources identified:identified. The OPUC issued an order on May 6, 2020 that acknowledged the following Action Plan for PGE to undertake:
•Customer actions—
◦Seek to acquire all cost-effective energy efficiency, reliance on demand response,efficiency; and dispatchable customer storage
◦Seek to acquire all cost-effective and standby generation;reasonable distributed flexibility.
•Renewable actions—Conduct a Renewable RFPRenewables Request for Proposals (RFP) seeking up to be conducted in 2020, seekingapproximately 150 MWa of new RPS-eligible resources that contribute to come onlinemeeting PGE’s capacity needs by 2023;the end of 2024,with the following conditions, among others:
◦Resources must qualify for the federal Production Tax Credit (PTC)or the federal Investment Tax Credit;
◦Resources must pass the cost-containment screen; and
◦The value of RECs generated prior to 2030 must be returned to customers.
•Capacity actions—a multi-stage procurement process that will allow PGE to pursuePursue dispatchable capacity through the following concurrent processes:
◦Pursue cost-competitive, bilateral contract agreements for existing capacity in the regionregion; and
◦Conduct an RFP for non-emitting dispatchable resources that contribute to conductmeeting PGE’s capacity needs.

The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of capacity contribution by 2025 from a combination of renewables, existing resources, and new non-emitting Capacity RFP in 2021 to fill any remainingdispatchable capacity needs, whichresources, such as energy storage. As PGE implements the Action Plan, the Company estimates will reach 595 MW by 2025, after considerationcontinue to evaluate present and ongoing resource needs in light of the Customereconomic disruption related to COVID-19.

PGE expects to file an IRP Update in 2020.

PGE and Renewable actions outlined above.
Douglas County Public Utility District have signed an agreement to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. The regulatory schedule for the 2019 IRP would lead to an OPUC order in the first quarter of 2020.

agreement also provides Douglas County PUD with PGE load management and wholesale market sales services.

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

Recovery of Renewable Recovery FrameworkEnergy Costs—The Renewable Adjustment Clause (RAC), asAs previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC. This mechanism allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year.annually to the OPUC. In the 2019 General Rate Case (GRC)(2019 GRC) Order, the OPUC also authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, to be made to the OPUC, under certain conditions. Although no significant filings have been submitted under

In the RAC duringfourth quarter of 2019, or 2018, the Company expects to submitsubmitted a RAC filing for Wheatridge beforerequesting recovery of the endnet revenue requirement of 2019.Wheatridge. If approved as requested, the Company would begin collection in customer prices upon the project’s in-service date, which is expected to occur prior to the inclusion of the project cost in base rates.
38
Table of Contents
Regulatory review of the request continues through a public process being conducted by the OPUC with a decision anticipated in the third quarter of this year. The wind facility is expected to be in-service in the fourth quarter of this year.


Building a Smarter, More Resilient GridElectrify other sectors of the economy—A smart grid allows PGE to work in collaboration with customers to integrate renewable energy and other technologies that improve efficiency and drive decarbonization. PGE is focused onworking toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:
•The use of electricity in more applications such as electric vehicles and heat pumps;
•The integration of new, geographically-diverse energy markets;
•The deployment of new technologies and the use of data analytics to better predict demand and supportlike energy saving customer programs. The Company is currently engaged in energy storage, initiatives, advanced communications networks, automation and control systems for flexible loads, and distributed generation, and thegeneration;
•The development of connected neighborhood microgrids and smart communities.communities; and

•The use of data and analytics to better predict demand and support energy-saving customer programs.
PGE considers the impact of making investments in new, renewable resource generation and energy storage facilities, as well as improvements to its transmission, distribution, and information technology infrastructure when determining capital requirements.

In 2018, PGE filedJuly 2019, PGE’s Board approved plans to construct an energy storage proposalIntegrated Operations Center (IOC) to support and enhance the reliability and resiliency of the grid and as a key step to support efforts to electrify the economy. The IOC, at an estimated total cost of $200 million, excluding AFDC, will centralize mission-critical operations, including those that called for 39 MWare planned as part of storagethe integrated grid strategy. This secure, resilient facility will include infrastructure to be developed oversupport and enhance grid operations and co-locate primary support functions. As of June 30, 2020, the next several years at various locations across the grid. In August 2018, the OPUC issued an order that outlined an agreed approachCompany has recorded $55 million, including AFDC, in CWIP related to the developmentIOC. The project is on track for an in-service completion date in the fourth quarter of five energy storage projects by PGE with an expected capital cost2021. The Company continues to actively monitor any potential supply chain or labor issues as a result of approximately $45 million.the COVID-19 pandemic.

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

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

41
Table of Contents


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

Pursuing Excellence in PGE’s WorkPerform as a business—PGE’s customer commitmentPGE focuses on providing reliable, clean power to customers at low costaffordable prices while providing a fair return to investors. Central toTo achieve this strategic initiative isgoal the Company must execute effectively within its regulatory framework and maintain prudent management of key legislative,financial, regulatory, and environmental matters that may affect customer prices and investor returns.

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

Under the power cost adjustment mechanism (PCAM) for 2019, NVPC waswithin the limits of the deadband, thus no potential refund or collection was recorded. The following discussion provides detail on several such material matters:OPUC will review the results of the PCAM for 2019 during the second half of 2020 with a decision expected in the fourth quarter 2020.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism—The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor site. As of June 30, 2020, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, and whether the final selection of a proposed remedy by the EPA will be implemented as issued. PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs and expects the next major phase of the allocation process to begin in January 2021, contemporaneously with the remedial design process that is just beginning. In a Record of Decision issued in 2017, the EPA outlined its selected
39
Table of Contents
remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. It is probable that PGE will share in a portion of the costs related to Portland Harbor, however the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation, although such costs could be material to PGE’s environmentalfinancial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company’s recovery mechanism allows the Company to defer and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices.prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA“EPA Investigation of Portland Harbor” Harbor” in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”


Power CostsCity of Portland Audit—Pursuant toIn 2019, the AUT process, PGE annually files an estimatecity of power costsPortland (the “City”), which is the largest city within PGE’s service territory, completed its audit of PGE’s and the City’s mutual License Fees agreement for the following year. As approved2012 through 2015 periods. The preliminary claim by the OPUCCity was that PGE improperly excluded certain items from the calculation of gross revenues, which resulted in December 2018,underpayment of franchise taxes of $7 million, including interest and penalties. PGE believes the 2019 GRC includedCity’s preliminary findings are not consistent with previous audit conclusions, which found that the Company appropriately calculated gross revenues in determining franchise fees. PGE believes it has a final projected increase in power costssound basis for 2019,maintaining the historical approach to determining License Fees and has not recorded a corresponding increase in annual revenue requirement, of $25 million from 2018 levels, which was reflected in customer prices effective January 1, 2019. The initial filingliability for the 2020 AUT indicated that power costs are expected to riseCity’s assertion. The City has not provided its Final Letter of Determination, which is an initial step in 2020. The final power cost update for 2020 will be filed November 15, 2019.an ongoing resolution process. Discussions with the City over this matter continue.

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

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

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

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

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

In response to the Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the OPUC Order with the Oregon Court of Appeals. Opening briefs were filed on September 20, 2019.Appeals, although the Court has indicated that the case would be dismissed given the lack of recent action in the case.

40
Table of Contents
On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility’s capital projects, including both depreciation expense and the cost of financing capital projects. PGE believes that the costs incurred to date associated with the customer information system were prudently incurred and has not withdrawn its deferral application to recover thethe revenue requirement of this capital project.

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

42
Table of Contents


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

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

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

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

In 2018, PGE collected from customers the $3 million of revenue that was recorded in 2016 that resulted from variances between actual weather-adjusted use per customer and that projected in the 2016 GRC. The Company recorded revenue for an estimated collection of $11$8 million duringfrom commercial customers for the yearsix months ended December 31, 2017,June 30, 2020, which resulted from variances between actual weather-adjusted use per customer and that projected in the 20162019 GRC. Collection from customers for the 2017 year is set to occur over a one-year period, which began January 1, 2019. The CompanyEstimated collections of $6 million recorded revenue for an estimated collection of $2 million during the year ended December 31, 2018, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2018 GRC. Any collection from customers, as approved, for the 2018 year is expected to occur over a one-year period, which would begin January 1, 2020.

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

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

As a result of the additional costs incurred, PGE filed an application with the OPUC requesting authorization to defer incremental storm related restoration costs from the date of the application, in the first quarter of 2017, through2020 from residential customers substantially reversed in the endsecond quarter bringing the year-to-date total to nearly zero. In the near term the Company expects to see, and has seen in the second quarter, higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation of 2017. In2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2020, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2022. The Company has $1 million remaining under the 2020 annual cap for commercial customers and expects to reach the cap during the third quarter of 2020. No cap exists for any potential refunds under the decoupling mechanism. At December 31, 2019, PGE recorded a total collection of $14 million, which if approved, will be collected over a one-year period beginning January 1, 2021.

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

In January 2020, at PGE’s request, the OPUC issued an order that deniedapproving a tariff and related deferral and balancing account to provide for an estimated recovery of $7 million in customer prices in 2020. The Company will revisit the Company’s application for deferral. Although PGE had deferredexpected tax consequences annually and revise the incremental expense in 2017, an offsetting reserve was also recorded at that time, thus the OPUC decision had no impactannual tariff accordingly. Pursuant to the Company’s current results of operations.

The discussion that followsorder, PGE started collections 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.


43
Table of Contents


Capital Requirements and Financing

customer prices February 1, 2020.
The Company expects 2019 capital expenditures to total $620 million, excluding AFDC. For additional information regarding estimated capital expenditures, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.

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

Operating Activities

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

The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price
41
Table of Contents
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—RetailThe following tables presents energy deliveries as well as the average number of customers in the various customer classes for the nineperiods indicated.

Three Months Ended June 30,% Increase (Decrease) in Energy
Deliveries		Six Months Ended June 30,% Increase (Decrease) in Energy
Deliveries
2020201920202019
Energy deliveries (MWhs in thousands):
Retail:
Residential1,658  1,526  9 %3,789  3,782  — %
Commercial1,374  1,630  (16)%3,000  3,261  (8)%
Industrial828  802  3 %1,638  1,510  8 %
Subtotal3,860  3,958  (2)%8,427  8,553  (1)%
Direct access:
Commercial141  177  (20)%311  341  (9)%
Industrial370  360  3 %725  720  1 %
Subtotal511  537  (5)%1,036  1,061  (2)%
Total retail energy deliveries4,371  4,495  (3)%9,463  9,614  (2)%
Wholesale energy deliveries1,287  785  64 %2,980  1,459  104 %
Total energy deliveries5,658  5,280  7 %12,443  11,073  12 %


Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Average number of retail customers:
Residential789,92788 %777,56488 %788,511  88 %776,81688 %
Commercial110,15812  109,19012  110,116  12  109,47012  
Industrial195—  192—  194  —  195—  
Direct access633—  634—  631  —  633—  
Total900,913  100 %887,580  100 %899,452  100 %887,114  100 %

The following table indicates the number of heating and cooling degree-days for the three and six months ended SeptemberJune 30, 2020 and 2019, increased 0.5% comparedalong with 15-year averages based on weather data provided by the nine months ended September 30, 2018,National Weather Service, as illustratedmeasured at Portland International Airport:
Heating Degree-daysCooling Degree-days
20202019Avg.20202019Avg.
First Quarter1,761  1,992  1,849  —  —  —  
April305  312  375  —  —  3  
May174  109  185  39  28  24  
June75  46  76  60  74  62  
Second Quarter554  467  636  99  102  89  
Year-to-date2,3152,4592,485  99  102  89  
(Decrease)/increase from the 15-year average(7)%(1)%11 %15 %

42
Table of Contents
During the second quarter, total heating degree days, while 13% below average, were 19% greater than 2019, thus indicating a higher demand for electricity during 2020. On a year-to-date basis, total heating degree-days were 6% below prior year totals, indicating that milder temperatures in the table below. This increase was primarily driven by continued growth infirst quarter had served to dampen demand. The impact of cooling degree-days, which have a greater impact on demand for energy deliveries from the Company’s industrial customers along with cooler temperatures during the heating season in the 2019 period, partially offset by milder weather duringupcoming third quarter of the summer cooling season.year in PGE’s service territory, was on par with 2019.

Retail energy deliveries for the first quarter of 2019 increased 4.3%six months ended June 30, 2020 decreased 2% compared with the prior year as cooler temperatures duringsix months ended June 30, 2019, which was attributed to an 8% decrease in commercial deliveries. Partially offsetting the 2019 heating season increased demand fromdecrease was a 6.0% increase in industrial deliveries, while residential deliveries were flat on the residential and commercial classes, while growth in demand continued from the Company’s industrial customers.year-to-date basis.

In the second quarter, of 2019, retail energy deliveries increased 0.2% overdecreased 3% compared to the same periodsecond quarter of 2018. Continued strength in2019. Commercial deliveries decreased 16% while energy deliveries to industrial customers was largely offset by the decreasesincreased 3%. Residential deliveries, which had been down 6% in the first quarter, were up 9% in the second quarter, bringing the six months year-to-date total to nearly the same level as the first six months of 2019. The large swing from the first to the second quarter of 2020 was due largely to the impact of the COVID-19 pandemic.

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

In the third quarter of 2019, retail energy deliveries decreased 3.2% asevolving customer demand was influenced by milder temperatures duringfor goods and services.

The following table shows the summer cooling season inpercentage contribution of the Company’s 2019 while 2018 saw excessively warm temperatures. Residential, commercial and industrial energy deliveries decreased 3.9%, 3.7%, and 1.4%, respectively, compared with the third quarterrevenues by category, some of 2018. On a weather-adjusted basis, energy deliveries were down 0.4% compared to the third quarter of 2018.which have seen, or may see, larger impacts from COVID-19 than others:

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

44
Table of Contents


CategoryPercentage of Commercial and Industrial Revenues
Manufacturing - High tech15 %
Manufacturing - Other13 
Office, Finance, Insurance, and Real Estate12 
Government and Education11 
Other Services11 
Miscellaneous Commercial8 
Other - Trade8 
Transportation, Utilities, and Warehousing6 
Restaurants and Lodging6 
Health Care6 
Food and Merchandise Stores4 
did not vary much from the prior year, or from 15-year averages, and play a fairly insignificant role in influencing customer demand during the third quarter of the year. See “Revenues” in the Results of Operations section of this Item 2 for further information on heating and cooling degree-days.

After adjusting for the effects of weather, retail energy deliveries for the ninesix months ended SeptemberJune 30, 2019 were comparable2020 increased 0.5% compared to the same period of 2018. Increased2019. The increase was driven by an increase of 4% in residential deliveries to high tech manufacturing customers have been largely offset byand 6% growth in industrial energy efficiency and conservation efforts and decreaseddeliveries. Commercial energy deliveries were down 7%. Residential average
43
Table of Contents
usage per customer. The financial effectscustomer saw an increase, which, combined with growth of such energy efficiency and conservation efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Decoupling”1.5% 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 residential customers, contributed to increased energy deliveries. PGE now expects that, while retail customersenergy deliveries for 2020 will continue to be impacted by customer type, and the correspondingCOVID-19 related behavioral changes, retail energy deliveries for the periods indicated:
full year 2020 will remain flat compared to 2019 weather-adjusted levels.
 Nine Months Ended September 30,  
 2019 2018 
% Increase (Decrease) in Energy
Deliveries
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Residential778,285
 5,428
 771,336
 5,457
 (0.5)%
          
Commercial (PGE sales only)109,509
 4,999
 108,566
 5,088
 (1.7)%
     Direct Access566
 536
 533
 481
 11.4 %
Total Commercial110,075
 5,535
 109,099
 5,569
 (0.6)%
          
Industrial (PGE sales only)194
 2,332
 204
 2,241
 4.1 %
     Direct Access67
 1,093
 66
 1,055
 3.6 %
Total Industrial261
 3,425
 270
 3,296
 3.9 %
          
Total (PGE sales only)887,988
 12,759
 880,106
 12,786
 (0.2)%
     Total Direct Access633
 1,629
 599
 1,536
 6.1 %
Total888,621
 14,388
 880,705
 14,322
 0.5 %
 *In thousands of MWhs.

The Company’s Retail Customer Choice Programcost-of-service opt-out 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 supplieddelivered to Direct Access customers.customers who purchase their energy from ESSs. This cap would have limited energy deliveries to these customers to an amount equal to approximately 14% of PGE’s total retail energy deliveries for the first ninesix months of 2019.2020. Actual energy deliveries to Direct Access customers represented 11% of PGE’s total retail energy deliveries for the first ninesix months of 20192020 and for the full year 2018.2019.

During 2018, the OPUC created a New Large Load Direct Access program capped at approximately 120 MWa, or 6% of total retail energy deliveries, for unplanned, large, new loads and large load growth at existing customer sites. The Company continuesIn early February 2020, PGE began offering service to work throughcustomers under this program, which is capped at 119 MWa, based on an order issued by the regulatory process to implement the new program.OPUC in January 2020.

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

 
Plant availability (1)
Actual energy provided compared to projected levels (2)
Actual energy provided as a percentage of total retail load
 202020192020201920202019
Generation:
Thermal:
Natural gas91 %92 %77 %79 %39 %36 %
Coal (3)
100  84  104  98  17  19  
Wind96  96  127  85  13  9  
Hydro90  97  77  85  8  9  
45
Table of Contents(1)



Plant availability represents the percentage of the period the plant was available for operations, which is impacted by planned maintenance and forced, or unplanned, outages, during whichoutages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the respective plantpower cost component of retail prices for the following calendar year. Any shortfall is unavailable to provide power. Availability of all the plants PGE operates was 94% and 93% during the nine months ended September 30, 2019 and 2018, respectively. generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability ofexcludes Colstrip, which PGE does not operate,operate. Colstrip availability was 88% and 80%78% during the ninesix months ended SeptemberJune 30, 20192020, compared with 88% in 2019.

Energy received from PGE-owned and 2018, respectively.

jointly-owned thermal plants decreasedDuring1% during the ninesix months ended SeptemberJune 30, 2019, the Company’s generating plants provided 87% of its retail load requirement compared with 75% in the nine months ended September 30, 2018. The increase in the proportion of power generated to meet the Company’s retail load requirement was largely due to PGE effectively dispatching its lowest-cost resources in a challenged market and increased plant availability of Colstrip during the nine months ended September 30, 20192020 compared to the nine months ended September 30, 2018.2019, primarily

as a result of strong performance for hydro and wind assets. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually inincreased 6% during the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the ninesix months ended SeptemberJune 30, 2019, energy received from these hydro resources decreased by 22%2020 compared to the nine months ended September 30, 2018. Energy received from these2019, due to more favorable hydro resources fell short of the projected levels includedconditions in PGE’s AUT by 17% for the nine months ended September 30, 2019 and approximated the projected levels for the nine months ended September 30, 2018, and provided 14% of the Company’s retail load requirement for the nine months ended September 30, 2019 and 18%for the nine months ended September 30, 2018. Energy received from hydro resources is expected to fall short of levels projected in the AUT for 2019 by up to 13%.

2020. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data.
44
Table of Contents

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

Under the AUT normally displaces power from higherPCAM, PGE may share with customers a portion of cost sources, while any shortfall is normally replacedvariances associated with power from higher cost sources. For the nine months ended September 30, 2019, energy received from these wind-powered generating resources decreased 9% comparedNVPC. Subject to the nine months ended September 30, 2018, resulting in the Company incurring additional replacement costs, as well as earning less PTCs than what was estimated in customer prices. Energy received from these wind-powered generating resources fell short of projections in PGE’s AUT by 6% for the nine months ended September 30, 2019 and fell short of projections in the AUT by 1% for the nine months ended September 30, 2018, and provided 10% and 11% of the Company’s retail load requirement during the nine months ended September 30, 2019 and 2018, respectively. Energy received from wind-powered resources is expected to fall short of levels projected in the AUT for 2019 by up to 5%.

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

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 ninesix months ended SeptemberJune 30, 2019,2020, actual NVPC was $5$38 million abovebelow baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 20192020 is currently estimated to be abovebelow the baseline, but

46
Table of Contents


within the established deadband range. Accordingly, no estimated refund to or collection from, customers is expected under the PCAM for 2019.2020.

•For the ninesix months ended SeptemberJune 30, 2018,2019, actual NVPC was $3$6 million below above baseline NVPC. For the year ended December 31, 2018,2019, actual NVPC was $3$5 million belowabove baseline NVPC, which was within the established deadband range. Accordingly, no estimated refundcollection to customers was recorded pursuant to the PCAM for 2018.2019.

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

Critical Accounting Policies

The Company’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018,2019, filed with the SEC on February 15, 2019.14, 2020.

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.


47
45
Table of Contents


The results of operations are as follows for the periods presented (dollars in millions):
Three Months Ended September 30, 
Nine Months Ended
September 30,
Three Months Ended June 30,% Increase (Decrease)Six Months Ended June 30,% Increase (Decrease)
2019 2018 2019 20182020201920202019
Total revenues$542
 100% $525
 100% $1,575
 100% $1,467
 100%Total revenues$469  $460  2 %$1,042  $1,033  1 %
Purchased power and fuel165
 30
 186
 35
 449
 29
 420
 29
Purchased power and fuel109  105  4 %262  284  (8)%
Gross margin(1)
377
 70
 339
 65
 1,126
 71
 1,047
 71
Gross margin(1)
360  355  1 %780  749  4 %
Other operating expenses:               Other operating expenses:
Generation, transmission and distribution78
 14
 72
 14
 241
 15
 212
 14
Generation, transmission and distribution77  86  (10)%150  163  (8)%
Administrative and other74
 14
 49
 9
 223
 14
 188
 13
Administrative and other74  78  (5)%145  149  (3)%
Depreciation and amortization103
 19
 96
 18
 305
 19
 281
 19
Depreciation and amortization104  101  3 %212  202  5 %
Taxes other than income taxes34
 7
 31
 6
 101
 7
 95
 7
Taxes other than income taxes34  33  3 %69  67  3 %
Total other operating expenses289
 54
 248
 47
 870
 55
 776
 53
Total other operating expenses289  298  (3)%576  581  (1)%
Income from operations88
 16
 91
 18
 256
 16
 271
 18
Income from operations71  57  25 %204  168  21 %
Interest expense(2)
32
 6
 31
 6
 95
 6
 93
 6
Interest expense(2)
34  31  10 %67  63  6 %
Other income:               Other income:
Allowance for equity funds used during construction2
 —
 2
 —
 7
 1
 8
 1
Allowance for equity funds used during construction4  2  100 %7  5  40 %
Miscellaneous income, net3
 1
 —
 —
 5
 —
 —
 —
Miscellaneous income (expense), netMiscellaneous income (expense), net3  —  — %(1) 2  (150)%
Other income, net5
 1
 2
 —
 12
 1
 8
 1
Other income, net7  2  250 %6  7  (14)%
Income before income tax expense61
 11
 62
 12
 173
 11
 186
 13
Income before income tax expense44  28  57 %143  112  28 %
Income tax expense6
 1
 9
 2
 20
 1
 23
 2
Income tax expense5  3  67 %23  14  64 %
Net income$55
 10% $53
 10% $153
 10% $163
 11%Net income$39  $25  56 %$120  $98  22 %
               
(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE’s Condensed Consolidated Statements of Income and Comprehensive Income.
(2) Net of an allowance for borrowed funds used during construction of $1 million for three months ended SeptemberJune 30, 2020 and 2019, and 2018$3 million and $4$2 million for the ninesix months ended SeptemberJune 30, 2020 and 2019, and 2018.

respectively.
Net income
46
was $55 million, or $0.61 per diluted share, for the three months ended September 30, 2019, compared with $53 million, or $0.59 per diluted share, for the three months ended September 30, 2018. Gross margin increased $38 million primarily due to a $21 million decrease in Purchased power and fuel expense. A combinationTable of lower retail load due to mild weather, lower wholesale power prices, and improved production from PGE-owned generation drove this decrease. Total revenues also increased by $17 million that included certain regulatory deferrals such as decoupling, which offset lower usage per customer within retail revenues ($7 million). Offsetting the increase in Gross margin were Operating expense increases of $41 million that resulted from a $4 million increase in distribution expenses due to higher vegetation management and wildfire mitigation efforts, higher labor and benefit expenses, and a $10 million gain from the cash settlement of Carty litigation in 2018 that did not recur.Contents

Net income was $153 million, or $1.70 per diluted share,- The following items contributed to the increase (decrease) in Net income for the ninethree and six months ended SeptemberJune 30, 2020 compared to the same periods in 2019 as follows (in millions):
Three Months EndedSix Months Ended
June 30, 2019$25  $98  
Items increasing (decreasing) Net income:
Decrease in Purchased power and fuel expense due to lower average variable power cost per MWh13  78  
Increase in Purchased power and fuel expense due to higher total system loads(17) (56) 
Decrease in other operating revenues primarily from the resale of excess natural gas used for fuel in 2019 that did not recur in 2020(4) (16) 
Change in average retail price10  12  
Decline in retail deliveries(11) (15) 
Increase in Wholesale revenues driven by increased volumes11  21  
Increase in bad debt expense(6) (6) 
Decrease in operating expenses as a result of decreased plant maintenance expense8  16  
Other10  (12) 
June 30, 2020$39  $120  
Change in Net income$14  $22  
47
Table of Contents
Three and six months ended June 30, 2020 compared with $163 million, or $1.82 per diluted share, for the ninethree and six months ended SeptemberJune 30, 2018. Gross margin increased $79 million due the combination of: a) $108 million increase in Total revenues, primarily due to price adjustments for the 2019 GRC, updated power costs and increases in revenues from wholesale market activities; and b) a $29 million increase in Purchased power and fuel expense due to higher average variable power cost.


48
Table of Contents


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

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

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

Three Months Ended June 30,Six Months Ended June 30,
Three Months Ended September 30,2020201920202019
2019 2018
Revenues (dollars in millions):       
Retail:       Retail:
Residential$218
 40% $224
 43 %Residential$223  48 %$205  45 %$502  48 %$495  48 %
Commercial167
 31
 171
 32
Commercial140  30  158  34  299  29  312  30  
Industrial50
 9
 55
 10
Industrial53  11  50  11  104  10  94  9  
Direct access13
 2
 9
 2
Direct AccessDirect Access12  3  10  2  23  2  21  2  
Subtotal448
 82
 459
 87
Subtotal428  91  423  92  928  89  922  89  
Alternative revenue programs, net of amortization4
 1
 —
 —
Alternative revenue programs, net of amortization—  —  (2) —  9  1  1  —  
Other accrued (deferred) revenues, net4
 1
 (11) (2)
Other accrued revenues, netOther accrued revenues, net1  —  6  1  6  1  13  1  
Total retail revenues456
 84
 448
 85
Total retail revenues429  91  427  93  943  91  936  90  
Wholesale revenues72
 13
 67
 13
Wholesale revenues27  6  16  3  74  7  53  5  
Other operating revenues14
 3
 10
 2
Other operating revenues13  3  17  4  25  2  44  5  
Total revenues$542
 100% $525
 100 %Total revenues$469  100 %$460  100 %$1,042  100 %$1,033  100 %
       
Energy deliveries (MWhs in thousands):
 
 
 
Retail:

 
 
 
Residential1,646
 24% 1,712
 27 %
Commercial1,738
 26
 1,837
 28
Industrial822
 12
 844
 13
Subtotal4,206
 62
 4,393
 68
Direct access:

 

 

 

Commercial195
 3
 170
 2
Industrial373
 5
 368
 6
Subtotal568
 8
 538
 8
Total retail energy deliveries4,774
 70
 4,931
 76
Wholesale energy deliveries2,015
 30
 1,529
 24
Total energy deliveries6,789
 100% 6,460
 100 %
       
Average number of retail customers:
 
 
 
Residential781,223
 88% 773,514
 88 %
Commercial109,589
 12
 110,028
 12
Industrial193
 —
 200
 —
Direct access632
 —
 604
 —
Total891,637
 100% 884,346
 100 %


49
Table of Contents


Total retail revenues — The following items contributed to the increase (decrease) in Total retail revenues for the three and six months ended SeptemberJune 30, 2020 compared to the same periods in 2019 increased $17 million compared with the three months ended September 30, 2018, as Total retail revenues increased $8 million, Wholesale revenues increased $5 million, and Other operating revenues increased $4 million.

The increase in Total retail revenues resulted largely from the following:
$16 million increase that resulted from customer price changes; partially offset by
$14 million decrease resulting from a 3.2% decrease in retail energy deliveries. Energy deliveries to residential customers decreased 3.9% reflecting decreased average usage per customer driven partially by mild weather, deliveries to commercial customers declined 3.7%, and deliveries to industrial customers decreased 1.4%.

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

The following table indicates the number of heating and cooling degree-days for the three months ended September 30, 2019 and 2018, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:follows (in millions):

 Heating Degree-days Cooling Degree-days
 2019 2018 Avg. 2019 2018 Avg.
July3
 2
 6
 176
 289
 179
August—
 6
 6
 216
 238
 190
September80
 61
 63
 70
 48
 71
Totals for the quarter83
 69
 75
 462
 575
 440
Increase/(decrease) from the 15-year average11% (8)%   5% 31%  
Three Months EndedSix Months Ended
June 30, 2019$427  $936  
Increase as a result of the change in the average price of kWhs delivered10  12  
Increase attributed to alternative revenue programs related to the decoupling mechanism2  8  
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertain to the demand response pilot program1  2  
Decrease from lower retail energy deliveries driven by the impact of COVID-19 in the second quarter 2020 and milder temperatures during the winter heating season in 2020(11) (15) 
June 30, 2020$429  $943  
Change in Total retail revenues$2  $7  


Wholesale revenues for the three months ended SeptemberJune 30, 20192020 increased $5$11 million, or 7%69%, from the three months ended SeptemberJune 30, 2018,2019, as a result of a $20$10 million increase related to 32%64% greater wholesale sales volume largely offset byand a $17$1 million decreaseincrease as a result of 20% lower4% higher average wholesale sales prices. Cooler weather

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


48
Table of Contents
Other operating revenues for the three months ended June 30, 2020 decreased $4 million from the three months ended June 30, 2019, the majority of which was the result of the sales of excess natural gas that occurred during 2019 that was not repeated in 2020.

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

Purchased power and fuel - expensedecreased$21 million, or 11%,The following items contributed to the increase (decrease) in Purchased power and fuel for the three and six months ended SeptemberJune 30, 2020 compared to the same periods in 2019 compared with the three months ended September 30, 2018. This change consisted of a $16 million decreaseas follows (dollars in themillions, except for average variable power cost per MWh, and a $5 million decrease due to total system load.MWh):

Three Months EndedSix Months Ended
June 30, 2019$105  $284  
Decrease related to average variable power cost per MWh(13) (78) 
Increase related to total system load17  56  
June 30, 2020$109  $262  
Change in Purchased power and fuel$4  $(22) 
Average variable power cost per MWh:
June 30, 2019$21.55  $26.92  
June 30, 2020$20.35  $21.98  
Total system load (MWhs in thousands):
June 30, 20194,91610,554
June 30, 20205,36411,950
The $16 million decrease due to a change in the average variable power cost per MWh to $25.16 per MWh for
For the three months ended SeptemberJune 30, 2019 from $29.98 per MWh for2020, the three months ended September 30, 2018, was primarily driven by a 10%$13 million decrease related to the change in average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 12% decline on the average cost of purchased power, combined with a 8% decline on the average cost for PGE’sthe Company’s own generation resources, and a 7% decrease for purchased power.

Althoughgeneration. The $17 million increase related to total system load increased 6%, PGE experienced an overall decreasewas primarily due to a 33% increase in purchased power, driven by lower gas prices and fuel attributablesurplus hydro in the region.

For the six months ended June 30, 2020, the $78 million decrease related to volume of $5the change in average variable power cost per MWh, was primarily driven by a decrease in the cost for purchased power, which declined 31% on a per MWh basis. The $56 million as a greater portion of PGE'sincrease related to total system load was satisfiedprimarily due to a 32% increase in purchased power, driven by PGE owned resources, which displaced higher cost market purchases when compared tolower gas prices and surplus hydro in the three months ended September 30, 2018.region.



5049
Table of Contents


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

Three Months Ended September 30,

2019
2018
Sources of energy (MWhs in thousands):






Generation:






Thermal:










Natural gas2,881

44%
2,777

45%
Coal1,450

22

1,054

17
Total thermal4,331

66

3,831

62
Hydro261

4

258

4
Wind598

9

475

8
Total generation5,190

79

4,564

74
Purchased power:






Term1,000

15

1,208

20
Hydro241

4

325

5
Wind100

2

85

1
Total purchased power1,341

21

1,618

26
Total system load6,531

100%
6,182

100%
Less: wholesale sales(2,015)


(1,529)

Retail load requirement4,516



4,653



Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas1,044  19 %1,150  23 %3,477  29 %3,318  31 %
Coal318  6  378  8  1,504  13  1,713  16  
Total thermal1,362  25  1,528  31  4,981  42  5,031  47  
Hydro317  6  460  9  686  6  837  8  
Wind608  11  608  13  1,193  10  820  8  
Total generation2,287  42  2,596  53  6,860  58  6,688  63  
Purchased power:
Term2,504  47  1,919  39  4,108  34  3,177  30  
Hydro459  9  319  6  804  7  566  6  
Wind114  2  82  2  178  1  123  1  
Total purchased power3,077  58  2,320  47  5,090  42  3,866  37  
Total system load5,364  100 %4,916  100 %11,950  100 %10,554  100 %
Less: wholesale sales(1,287) (785) (2,980) (1,459) 
Retail load requirement4,077  4,131  8,970  9,095  
Energy received from PGE-owned, wind-powered generating resources increased 26% in the three months ended September 30, 2019 compared with the same period of 2018 as a result of more favorable windconditions. Energy received from these wind-powered generating resources represented 13% of the Company’s retail load requirements for the three months ended September 30, 2019 and 10% for the three months ended September 30, 2018.

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

The following table presents the forecasted April-to-September 2020 and the actual April-to-September 2019 and 2018 runoff at particular points of major rivers relevant to PGE’s hydro resources:
 Runoff as a Percent of Normal*
Location2019 2018
Columbia River at The Dalles, Oregon94% 114%
Mid-Columbia River at Grand Coulee, Washington87
 114
Clackamas River at Estacada, Oregon114
 88
Deschutes River at Moody, Oregon111
 88

Runoff as a Percent of Normal*
Location2020 Forecast2019 Actual
Columbia River at The Dalles, Oregon106 %94 %
Mid-Columbia River at Grand Coulee, Washington111  87  
Clackamas River at Estacada, Oregon78  114  
Deschutes River at Moody, Oregon87  111  
* Volumetric water supply forecasts and historical averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center, with the Natural Resources Conservation Service and other cooperating agencies.

Actual NVPC- The following items contributed to the increase (decrease) in Actual NVPC for the three and six months ended SeptemberJune 30, 2020 compared to the same periods in 2019 decreased $26 million when compared with the three months ended September 30, 2018. The decrease was primarily driven by a 7% increase in wholesale revenue.as follows (in millions):

Three Months EndedSix Months Ended
June 30, 2019$89  $231  
Increase (Decrease) in Purchased power and fuel expense4  (22) 
Increase in Wholesale revenues(11) (21) 
June 30, 2020$82  $188  
Change in NVPC$(7) $(43) 

See “Purchased power and fuel expense” and The increase in wholesale revenues was driven by a 32% increase in the wholesale volume. “Revenues” within this “Results of Operations” for more details.
50
Table of Contents
For the three months ended SeptemberJune 30, 2020 and 2019, actual NVPC was $2$18 million below the baseline.baseline and $6 million below the baseline NVPC, respectively. For the threesix months ended SeptemberJune 30, 2018,2020 and 2019, actual
NVPC was $24$38 million below and $6 million above baseline NVPC. For additional information, see “Purchased power and fuel” section of this Item 2.NVPC, respectively.

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

Generation, transmission and distribution expense increased $6 million, or 8%,- The following items contributed to the decrease in Generation, transmission and distribution for the three and six months ended SeptemberJune 30, 2020 compared to the same periods in 2019 compared with the three months ended September 30, 2018, due to $6 million higher distribution expenses for vegetation management, wildfire mitigation and preventative maintenance, $3 million lower expenses at the Company’s generation facilities, and $3 million higher miscellaneous expenses.as follows (in millions):

Three Months EndedSix Months Ended
June 30, 2019$86  $163  
Lower operating and plant maintenance expenses at the Company’s generation facilities(10) (15) 
Lower distribution expenses for vegetation management and storm restoration(2) (1) 
Miscellaneous expenses3  3  
June 30, 2020$77  $150  
Change in Generations, transmission and distribution$(9) $(13) 

Administrative and other - The following items contributed to the increase (decrease) in Administrative and other for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):
Three Months EndedSix Months Ended
June 30, 2019$78  $149  
Increase to bad debt expense6  6  
Lower employee benefits expense(3) (4) 
Lower outside services(3) (3) 
Miscellaneous expenses(4) (3) 
June 30, 2020$74  $145  
Change in Administrative and other$(4) $(4) 

COVID-19 may prospectively impact Administrative and other expenses, particularly if economic shutdowns increase bad debt expense increased$25 million, or 51%,by driving higher unemployment and impact the revenue of businesses in the three months ended September 30, 2019 compared withCompany’s service territory. PGE expects that the three months ended September 30, 2018. The increase was primarily duecombination of actions benefiting customers, such as suspending disconnections and late fee penalties, and regional economic factors will likely result in significant increases to a $10bad debt expense, which is currently projected to be $15 million expense reduction in 2018 related to the Carty cash settlement, an $8 million increase in employee benefit costs, and a $7 million increase in other miscellaneous expenses that included system conversion costs, and customer-related charges and injury and damages expenses.for 2020.

51
Table of Contents
Depreciation and amortization - The following items contributed to the increase (decrease) in Depreciation and amortization for the three and six months ended June 30, 2020 compared to the same periods in 2019 as follows (in millions):
Three Months EndedSix Months Ended
June 30, 2019$101  $202  
Increased depreciation and amortization expense from capital additions1  3  
Increased amortization related to regulatory programs (offset in revenues)5  10  
    Miscellaneous expenses(3) (3) 
June 30, 2020$104  $212  
Change in Depreciation and amortization$3  $10  

Interest expense, netincreased $7$3 million and $4 million, in the threeandsix months ended SeptemberJune 30, 2019 compared with the three months ended September 30, 2018. The increase was driven by a $6 million2020, respectively, primarily due to an increase in amortizationthe average balance of regulatory deferrals (which is offset in revenues)outstanding debt and $5 million higher depreciation and amortization expense resulting from capital additions. In the third quarter 2018, the Company incurred a $4 million charge as a result of an increase to asset retirement obligations.interest on additional finance leases.

Other income, net increased $3$5 million and decreased $1 million for the three and six months ended SeptemberJune 30, 2019 compared with the three months ended September 30, 2018,2020, respectively, primarily due to a curtailment gain recognized in 2019 due tomarket changes in retiree medical plans.on the non-qualified benefit trust.

Income tax expense decreased $3increased $2 million in theand $9 million for three and six months ended SeptemberJune 30, 2020, respectively, compared to the same periods in 2019, compared with the three months ended September 30, 2018, reflecting effective tax rates of 9.8%and14.5%, respectively. The decrease in income tax expense was driven by amortization of excess deferred taxes as a result of TCJA.

51
Table of Contents


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

Revenues, energy deliveries (presented in MWhs), and the average number of retail customers consist of the following for the periods presented:
 Nine Months Ended September 30,
 2019 2018
Revenues (dollars in millions):       
Retail:       
Residential$713
 45% $699
 48 %
Commercial479
 31
 484
 33
Industrial144
 9
 138
 9
Direct Access34
 2
 32
 2
Subtotal1,370
 87
 1,353
 92
Alternative revenue programs, net of amortization5
 —
 (2) —
Other accrued (deferred) revenues, net17
 1
 (38) (3)
Total retail revenues1,392
 88
 1,313
 89
Wholesale revenues125
 8
 119
 8
Other operating revenues58
 4
 35
 3
Total revenues$1,575
 100% $1,467
 100 %
        
Energy deliveries (MWhs in thousands):       
Retail:       
Residential5,428
 31% 5,457
 31 %
Commercial4,999
 28
 5,088
 29
Industrial2,332
 13
 2,241
 12
Subtotal12,759
 72
 12,786
 72
Direct access:       
Commercial536
 3
 481
 3
Industrial1,093
 6
 1,055
 6
Subtotal1,629
 9
 1,536
 9
Total retail energy deliveries14,388
 81
 14,322
 81
Wholesale energy deliveries3,474
 19
 3,444
 19
Total energy deliveries17,862
 100% 17,766
 100 %
        
Average number of retail customers:       
Residential778,285
 88% 771,336
 88 %
Commercial109,509
 12
 108,566
 12
Industrial194
 —
 204
 —
Direct access633
 —
 599
 —
Total888,621
 100% 880,705
 100 %


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


52
Table of Contents


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

$38 million as a result of customer price changes in the 2019 GRC;
$17 million as a result of price changes due primarily to the 2019 AUT and the amortization in prices for the decoupling mechanism;
$11 million resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertain to the demand response pilot program and a major maintenance expense deferral, which was offset in Generation, transmission and distribution expense; and
$6 million from higher retail energy deliveries driven by the industrial customers.

Total heating degree-days for the nine months ended September 30, 2019 were 10% above those for the nine months ended September 30, 2018 although 1% below the 15-year average, while cooling degree-days, which usually begin during the second calendar quarters, were 18% below the prior year levels. The following table indicates the number of heating and cooling degree-days by quarter for the nine months ended September 30, 2019 and 2018, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:
 Heating Degree-days Cooling Degree-days
 2019 2018 Avg. 2019 2018 Avg.
First Quarter1,992
 1,766
 1,830
 —
 —
 —
Second Quarter467
 471
 653
 102
 116
 88
Third Quarter83
 69
 75
 462
 575
 440
Year-to-date2,542
 2,306
 2,558
 564
 691
 528
(Decrease)/increase from the 15-year average(1)% (10)%   7% 31%  

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

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

Purchased power and fuel expense increased$29 million, or7%, for the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. This change consisted of $56 million increase related to the average variable power cost per MWh, and a $27 million decrease related to total system load.

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

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


53
Table of Contents


The sources of energy for PGE’s total system load, as well as its retail load requirement, were as follows:
 Nine Months Ended September 30,
 2019 2018
Sources of energy (MWhs in thousands):       
Generation:       
Thermal:       
Natural gas6,199
 36% 5,468
 32%
Coal3,163
 19
 2,020
 12
Total thermal9,362
 55
 7,488
 44
Hydro1,098
 7
 1,125
 7
Wind1,418
 8
 1,563
 9
Total generation11,878
 70
 10,176
 60
Purchased power:
   
 
Term4,177
 24
 5,339
 31
Hydro807
 5
 1,331
 8
Wind223
 1
 237
 1
Total purchased power5,207
 30
 6,907
 40
Total system load17,085
 100% 17,083
 100%
Less: wholesale sales(3,474)   (3,444)  
Retail load requirement13,611
   13,639
  

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

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

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

Generation, transmission and distribution expense increased$29 million, or 14%, in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018increases primarily due to $15higher pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

Credit market disruptions caused by the impacts of COVID-19 have increased liquidity concerns. PGE’s capacity to respond to liquidity issues and credit market disruptions is supported by: i) a $500 million higher distribution expenses for vegetation management, wildfire mitigationrevolving credit facility; ii) $220 million in letter of credit facilities; iii) strong investment grade credit ratings with multiple agencies; iv) significant capacity to issue additional debt within existing debt covenant restrictions; and storm restoration, $11v) continued access to capital markets demonstrated by an issuance of a $150 million higher operating and preventative maintenance expenses at the Company’s generation facilities, and $4 million higher miscellaneous expenses.

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

Depreciation and amortization expense increased $24 million, or 9%, in the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. The increase was primarily driven by higher depreciation and amortization expense of $18 million from capital additions, partially offset by a $4 million increase in 2018 to asset retirement obligations,364-day term loan and a $9$200 million increaseFMB issuance in April 2020. The Company has the ability to amortization of regulatory deferrals (directly offset in revenues).

Taxes other than income taxesexpand the revolving credit facility to $600 million, if needed. increased $6 million, or 6%, in the nine months ended September 30, 2019 comparedPGE continues to the nine months ended September 30, 2018, driven by higher property taxes.

Other income, net wasmonitor credit market conditions to identify additional actions to support anticipated capital and operating requirements. $12 million in the nine months ended September 30, 2019 compared with $8 million in the nine months ended September 30, 2018, driven by a curtailment gain recognized in 2019 due to changes in retiree medical plans and decreased pension expense due to changes in actuarial valuations.

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

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2019through2023 (in millions, excluding AFDC):
 2019 2020 2021 2022 2023
Ongoing capital expenditures*$585
 $640
 $500
 $500
 $500
Wheatridge Renewable Energy Facility5
 135
 15
 —
 —
Integrated Operations Center30
 90
 80
 —
 —
Total capital expenditures$620
 $865
 $595
 $500
 $500
Long-term debt maturities$50
 $—
 $160
 $—
 $—

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

54
Table of Contents



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

Liquidity

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

The following summarizes PGE’s cash flows for the periods presented (in millions):
52
Table of Contents
Nine Months Ended September 30,Six Months Ended June 30,
2019 201820202019
Cash and cash equivalents, beginning of period$119
 $39
Cash and cash equivalents, beginning of period$30  $119  
Net cash provided by (used in):   Net cash provided by (used in):
Operating activities502
 536
Operating activities356  314  
Investing activities(406) (278)Investing activities(370) (271) 
Financing activities(204) (97)Financing activities287  (151) 
(Decrease) increase in cash and cash equivalents(108) 161
(Decrease) increase in cash and cash equivalents273  (108) 
Cash and cash equivalents, end of period$11
 $200
Cash and cash equivalents, end of period$303  $11  

Cash Flows from Operating Activities — 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. NetThe following items contributed to the net change in cash flows from operating activitiesoperations for the ninesix months ended SeptemberJune 30, 2019 decreased $34 million when2020 compared with the ninesix months ended SeptemberJune 30, 2018. Included in the change were:2019 (in millions):
$53 million decrease relating to TCJA as a deferral occurred in 2018 with amortization recorded in 2019;
$42 million decrease resulting from changes in Accounts payable and other accrued liabilities; and
$10 million decrease in Net income; partially offset by
$38 million increase from changes in Accounts receivable and unbilled revenues;
$30 million increase in Other non-cash income and expenses, net; and
$24 million increase resulting from Depreciation and amortization.
Increase/
(Decrease)
Accounts payable and other accrued liabilities$38 
Other non-cash income and expenses, net25 
Net income22 
Margin deposits primarily due to additional collateral requirements as the result of market conditions(20)
Accounts receivable, net(23)
Net change in cash flow from operations$42 
Cash provided by operations includes the recovery in customer prices of
PGE estimates that non-cash charges for depreciation and amortization. PGE estimates that such chargesamortization in 20192020 will range from $400$410 million to $420$430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $475$550 million to $525$600 million. The range of expected cash provided by operations has decreased primarily due to the planned acceleration of $62 million in pension plan contributions. For additional information, see “Contractual Obligations” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation facilities and transmission and

55
Table of Contents


distribution systems. Net cash used in investing activities for the ninesix months ended SeptemberJune 30, 20192020 increased $128$99 million when compared with the ninesix months ended SeptemberJune 30, 2018, with the difference largely due to $120 million cash received in 20182019, as capital expenditures increased as a result of a litigation settlement.

construction underway for Wheatridge and the IOC in 2020.
The
Excluding AFDC, the Company plans to make capital expenditures of $620$740 million excluding AFDC, in 2019,2020, which it expects to fund with cash to be generated from operations during 2019,2020, as discussed above, and the issuance of debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the ninesix months ended SeptemberJune 30, 2019, a2020, net usecash provided by financing activities was primarily the result of cash resultedproceeds from the payment of $300 million of long-term debt that was funded through the issuancecombination of $200 million of FMBs issued, the $150 million term loan, and available cash on hand and payment$21 million from the remarketing of $99 million of dividends. DuringPCRBs previously held by the nine months ended September 30, 2018, net cash used in financing activitiesconsisted primarily ofCompany, partially offset by the payment of dividends$69 million of $93 million.dividends.

53
Dividends on Common Stock
Table of Contents

Capital Requirements
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,following table presents PGE’s results of operations and financial condition, futureestimated capital expenditures and investments,contractual maturities of long-term debt for 2020through2024 (in millions, excluding AFDC).
20202021202220232024
Ongoing capital expenditures*$550  $450  $500  $500  $500  
Wheatridge Renewable Energy Facility120  15  —  —  —  
Integrated Operations Center70  100  —  —  —  
Total capital expenditures$740  $565  $500  $500  $500  
Long-term debt maturities$—  $160  $—  $—  $80  
* Consists primarily of upgrades to, and applicable regulatoryreplacement of, generation, transmission, and contractual restrictions.distribution infrastructure, as well as new customer connections. Includes preliminary engineering and removal costs.

Common stock dividends declared during 2019 consist of the following:
Dividends
Declared Per
Declaration DateRecord DatePayment DateCommon Share
February 13, 2019March 25, 2019April 15, 2019$0.3625
April 24, 2019June 25, 2019July 15, 20190.3850
July 31, 2019September 25, 2019October 15, 20190.3850
October 30, 2019December 26, 2019January 15, 20200.3850

Debt and Equity Financings

PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors.factors, such as the significant volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future.

For 2019,2020, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $475550 million to $525$600 million, issuances of debt securities of up to $520410 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.expenditures and debt payments.

Short-term Debt. PGE has approval from the FERCFederal Energy Regulatory Commission to issue short-term debt up to a total of $900$900 million through February 6,7, 2022. The following table shows available liquidity as of June 30, 2020. (in millions):

As of June 30, 2020
CapacityOutstandingAvailable
Revolving credit facility (1)
$500  $—  $500  
Letters of credit (2)
220  46  174  
Total credit$720  $46  $674  
Cash and cash equivalents303  
Total liquidity$977  

56
Table of Contents(1)


As of September 30, 2019, PGE had a $500 million revolving credit facility scheduledScheduled to expire in November 2022. 2023.
(2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.

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

54
Table of Contents
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.

UnderThe Company has elected to limit its borrowings under the revolving credit facility as of September 30, 2019, PGE had no borrowings orin order to allow coverage for the potential need to repay any commercial paper outstanding. Asthat may be outstanding at the time.

On April 9, 2020, PGE obtained a result,364-day, term loan in the aggregate unused available credit capacity was $500 million.

In addition, PGE has four letterprincipal of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $220$150 million. The issuance of such letters of creditterm loan will bear interest for the relevant interest period at the London Inter-Bank Offered Rate plus 1.25%. The interest rate is subject to adjustment pursuant to the approvalterms of the issuing institution. Under these facilities, letters ofloan. The credit for a total of$60 million wereagreement expires on April 8, 2021, with any outstanding as of September 30, 2019.balance due and payable on such date.

Long-term Debt. As of SeptemberJune 30, 2019,2020, total long-term debt outstanding, net of $10$13 million of unamortized debt expense, was $2,378$2,816 million.

On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds, which $50consist of the refinancing of $98 million is expected to maturepreviously outstanding that will now bear an interest rate of 2.125%, and $21 million previously held by PGE for remarketing that will bear an interest rate of 2.375%, both due in 2019. 2033.

On April 12, 2019,27, 2020, PGE issued $200 million FMBs at an interest rate of 4.30%,3.15% Series First Mortgage Bonds (FMBs) due in 2049. Proceeds from the transaction were used toward repayment of the $300 million current portion of long-term debt that came due April 15, 2019.2030.

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

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including any current debt maturities) of approximately 50%, over time. Achievement of this objective helps the Company maintain investment grade credit ratings and facilitates access to long-term capital at favorable interest rates. The Company’s common equity ratio was 50.3%45.6% and 49.8%48.1% as of SeptemberJune 30, 20192020 and December 31, 2018,2019, respectively.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows:
Moody’sS&P
First Mortgage BondsA1A
Senior unsecured debtA3BBB+
Commercial paperP-2A-2
OutlookStablePositive

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 SeptemberJune 30, 2019,2020, PGE had $33$31 million of collateral posted with these counterparties, consisting of $1225 million in cash and $216 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 SeptemberJune 30, 2019,2020, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was $37$17 million, and decreases to $234 million by December 31, 20192020 and to$7 millionnone by December 31, 2020.2021. The amount of additional collateral that could be requested
55
Table of Contents
upon a dual agency downgrade to below investment grade was $107$106 million at SeptemberJune 30, 20192020 and decreases to $8884 million by December 31, 20192020 and to $6371 million by December 31, 2020.2021.

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

The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on SeptemberJune 30, 2019,2020, under the most restrictive issuance test in the Indenture, the Company could have issued up to $908$955 million of additional

57
Table of Contents


FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of SeptemberJune 30, 2019,2020, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 50.2%54.4%.

Off-Balance Sheet Arrangements

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

For suchPGE’s surety bond and letter of credit arrangements set forthare described in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018,2019, filed with the SEC on February 15, 2019.14, 2020, there have been no material changes outside the ordinary course of business as of SeptemberJune 30, 2019.2020, with the exception of an increase of $26 million to the surety bonds PGE has provided on behalf of the operator of Colstrip for a total of $44 million.

Contractual Obligations

PGE’s contractual obligations for 20192020 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, 2018,2019, filed with the SEC on February 15, 2019.14, 2020. For such obligations, there have been no material changes outside the ordinary course of business as of SeptemberJune 30, 2019 except that2020.
PGE expects to accelerate previously planned contributions to the pension plan during 2020 and 2021 into 2019, such that it will fund $62 million in 2019 and none in either 2020 or 2021.

Item 3.Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. There have been no material changes to market risks, or credit risk, affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018,2019, filed with the SEC on February 15, 2019.14, 2020.

Item 4.Controls and Procedures.
 
Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s
56
Table of Contents
Chief Executive Officer and Chief Financial Officer have concluded that, as of SeptemberJune 30, 2019,2020, these disclosure controls and procedures were effective.


58
Table of Contents


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.

ThereOther than items noted below, there have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018,2019, filed with the SEC on February 15, 2019.14, 2020.

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

Item 5.Other Information.

On October 30, 2019,The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide. Measures to control the spread of COVID-19 have affected the demand for the products and services of many businesses in PGE’s service territory and disrupted supply chains around the world. Although the full scope and extent of the impacts of COVID-19 on the Company’s operations remain uncertain, PGE has experienced a reduction in load and an increase in past due accounts and late customer payments. Management believes that these trends will have an impact on its results of operations in 2020 and possibly subsequent periods. PGE continues to monitor the impacts of the COVID-19 pandemic on its workforce, liquidity, capital markets, reliability, cybersecurity, customers, and suppliers, along with overall macroeconomic conditions. Although the Company entered into an agreementcannot predict with William Nicholson, Vice President, Utility Technical Services, in connection with his planned retirement fromcertainty the Company on December 31, 2019. The agreement includes a standard release of claims against the Company and provides for the following benefits: accelerated vesting of 837 time-based restricted stock units that would otherwise have been forfeited upon Mr. Nicholson’s retirement on December 31, 2019; and amendment of two outstanding performance-based restricted stock unit awards to provide for continued vesting subject to Company performance through the endfull extent of the applicable performance period. AsCOVID-19 pandemic’s impact on its business, a resultprotracted slowdown of broad sectors of the amendmenteconomy, changes in demand for commodities, or significant changes in legislation or regulatory policy to address the COVID-19 pandemic could result in a significant reduction in demand for electricity in PGE’s service territory, increased late customer payments or uncollectible accounts, and the inability of the performance-based restricted stock units, dependent upon Company performance, Mr. Nicholson will remain eligibleCompany’s contractors, suppliers, and other business partners to receive upfulfill their contractual obligations, any of which could have, or continue to 7,716 shareshave, a material adverse effect on the Company’s results of Company common stock (4,354 shares at the target level of performance) that he would have otherwise forfeited.operations, financial condition and cash flows.



59
Table of Contents


Item 6.Exhibits.
57
Table of Contents
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
31.2
32
101.INS
101.INSXBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCHXBRL Taxonomy Extension Schema Document.
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
101.LABXBRL Taxonomy Extension Label Linkbase Document.
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
104Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed November 1, 2019,July 30, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language).

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


60
Table of Contents


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)
PORTLAND GENERAL ELECTRIC COMPANY
Date:July 30, 2020(Registrant)
By:
Date:October 31, 2019By:/s/ James F. Lobdell
James F. Lobdell
Senior Vice President of Finance,

Chief Financial Officer and Treasurer
(duly authorized officer and principal financial officer)

6158