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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

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

For the quarterly period ended September 30, 2021
or

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

For the transition period from ____________________ to ____________________
Commission File Number: 001-5532-99
PORTLAND GENERAL ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

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

121 SW Salmon Street
Portland, Oregon 97204
(503) 464-8000
(Address of principal executive offices, including zip code,
and registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

(Title of class) | (Trading Symbol) | (Name of exchange on which registered)
Common Stock, no par value | POR | New York Stock Exchange

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

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, 2021 is 89,409,613 shares.

1

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2021
TABLE OF CONTENTS

Definitions | 3
PART I — FINANCIAL INFORMATION
Item 1. | Financial Statements (Unaudited) | 4
| Condensed Consolidated Statements of Income and Comprehensive Income | 4
| Condensed Consolidated Balance Sheets | 5
| Condensed Consolidated Statements of Cash Flows | 7
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 36
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 63
Item 4. | Controls and Procedures | 63
PART II — OTHER INFORMATION
Item 1. | Legal Proceedings | 63
Item 1A. | Risk Factors | 63
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 59
Item 5. | Other Information | 64
Item 6. | Exhibits | 64
SIGNATURE | 66

2

Table of Contents
DEFINITIONS
The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym |  | Definition
AFDC |  | Allowance for funds used during construction
AUT |  | Annual Power Cost Update Tariff
Colstrip |  | Colstrip Units 3 and 4 coal-fired generating plant
EPA |  | United States Environmental Protection Agency
FERC |  | Federal Energy Regulatory Commission
FMBs |  | First Mortgage Bonds
GAAP |  | Accounting principles generally accepted in the United States of America
GRC |  | General Rate Case
IRP |  | Integrated Resource Plan
Moody’s |  | Moody’s Investors Service
MW |  | Megawatts
MWa |  | Average megawatts
MWh |  | Megawatt hour
Nasdaq |  | National Association of Securities Dealers Automated Quotations
NVPC |  | Net Variable Power Costs
NYSE |  | New York Stock Exchange
OPUC |  | Public Utility Commission of Oregon
PCAM |  | Power Cost Adjustment Mechanism
RPS |  | Renewable Portfolio Standard
S&P |  | S&P Global Ratings
SEC |  | United States Securities and Exchange Commission
Wheatridge |  | Wheatridge 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 September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Revenues: |  |  |  |  |  |  |
Revenues, net | $ | 654 |  |  | $ | 556 |  |  | $ | 1,811 |  |  | $ | 1,589 |
Alternative revenue programs, net of amortization | (12) |  |  | (9) |  |  | (23) |  |  | — |
Total revenues | 642 |  |  | 547 |  |  | 1,788 |  |  | 1,589 |
Operating expenses: |  |  |  |  |  |  |
Purchased power and fuel | 259 |  |  | 292 |  |  | 613 |  |  | 554 |
Generation, transmission and distribution | 80 |  |  | 65 |  |  | 236 |  |  | 215 |
Administrative and other | 82 |  |  | 63 |  |  | 247 |  |  | 208 |
Depreciation and amortization | 101 |  |  | 108 |  |  | 305 |  |  | 320 |
Taxes other than income taxes | 37 |  |  | 35 |  |  | 110 |  |  | 104 |
Total operating expenses | 559 |  |  | 563 |  |  | 1,511 |  |  | 1,401 |
Income (loss) from operations | 83 |  |  | (16) |  |  | 277 |  |  | 188 |
Interest expense, net | 33 |  |  | 35 |  |  | 100 |  |  | 102 |
Other income: |  |  |  |  |  |  |
Allowance for equity funds used during construction | 4 |  |  | 4 |  |  | 13 |  |  | 11 |
Miscellaneous income (expense), net | 1 |  |  | 3 |  |  | 6 |  |  | 2 |
Other income, net | 5 |  |  | 7 |  |  | 19 |  |  | 13 |
Income (loss) before income tax expense | 55 |  |  | (44) |  |  | 196 |  |  | 99 |
Income tax expense (benefit) | 5 |  |  | (27) |  |  | 18 |  |  | (4) |
Net income (loss) | 50 |  |  | (17) |  |  | 178 |  |  | 103 |
Other comprehensive income | 1 |  |  | — |  |  | 1 |  |  | 1 |
Comprehensive income (loss) | $ | 51 |  |  | $ | (17) |  |  | $ | 179 |  |  | $ | 104 |
Weighted-average common shares outstanding (in thousands): |  |  |  |  |  |  |
Basic | 89,407 |  |  | 89,509 |  |  | 89,505 |  |  | 89,476 |
Diluted | 89,566 |  |  | 89,509 |  |  | 89,646 |  |  | 89,629 |
Earnings (loss) per share: |  |  |  |  |  |  |
Basic | $ | 0.56 |  |  | $ | (0.19) |  |  | $ | 1.99 |  |  | $ | 1.16 |
Diluted | $ | 0.56 |  |  | $ | (0.19) |  |  | $ | 1.98 |  |  | $ | 1.15 |
See accompanying notes to condensed consolidated financial statements.

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

| September 30, 2021 |  | December 31, 2020
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 294 |  |  | $ | 257 |
Accounts receivable, net | 273 |  |  | 271 |
Inventories | 75 |  |  | 72 |
Regulatory assets—current | 14 |  |  | 23 |
Other current assets | 243 |  |  | 98 |
Total current assets | 899 |  |  | 721 |
Electric utility plant, net | 7,773 |  |  | 7,539 |
Regulatory assets—noncurrent | 567 |  |  | 569 |
Nuclear decommissioning trust | 43 |  |  | 45 |
Non-qualified benefit plan trust | 44 |  |  | 42 |
Other noncurrent assets | 216 |  |  | 153 |
Total assets | $ | 9,542 |  |  | $ | 9,069 |
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)

| September 30, 2021 |  | December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 201 |  |  | $ | 153 |
Liabilities from price risk management activities—current | 39 |  |  | 14 |
Short-term debt | — |  |  | 150 |
Current portion of long-term debt | — |  |  | 160 |
Current portion of finance lease obligation | 16 |  |  | 16 |
Accrued expenses and other current liabilities | 611 |  |  | 322 |
Total current liabilities | 867 |  |  | 815 |
Long-term debt, net of current portion | 3,285 |  |  | 2,886 |
Regulatory liabilities—noncurrent | 1,370 |  |  | 1,369 |
Deferred income taxes | 419 |  |  | 374 |
Unfunded status of pension and postretirement plans | 299 |  |  | 299 |
Liabilities from price risk management activities—noncurrent | 89 |  |  | 136 |
Asset retirement obligations | 241 |  |  | 270 |
Non-qualified benefit plan liabilities | 97 |  |  | 101 |
Finance lease obligations, net of current portion | 125 |  |  | 129 |
Other noncurrent liabilities | 75 |  |  | 77 |
Total liabilities | 6,867 |  |  | 6,456 |
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, 2021 and December 31, 2020 | — |  |  | — |
Common stock, no par value, 160,000,000 shares authorized; 89,409,012 and 89,537,331 shares issued and outstanding as of September 30, 2021 and December 31, 2020, respectively | 1,237 |  |  | 1,231 |
Accumulated other comprehensive loss | (10) |  |  | (11) |
Retained earnings | 1,448 |  |  | 1,393 |
Total shareholders’ equity | 2,675 |  |  | 2,613 |
Total liabilities and shareholders’ equity | $ | 9,542 |  |  | $ | 9,069 |
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)

| Nine Months Ended September 30,
| 2021 |  | 2020
Cash flows from operating activities: |  |  |
Net income | $ | 178 |  |  | $ | 103 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation and amortization | 305 |  |  | 320 |
Deferred income taxes | 17 |  |  | (14) |
Pension and other postretirement benefits | 19 |  |  | 17 |
Allowance for equity funds used during construction | (13) |  |  | (11) |
Decoupling mechanism deferrals, net of amortization | 23 |  |  | — |
Amortization of net benefits due to Tax Reform | — |  |  | (17) |
Deferral of incremental storm costs | (58) |  |  | — |
Other non-cash income and expenses, net | (1) |  |  | 38 |
Changes in working capital: |  |  |
(Increase)/decrease in accounts receivable, net | (8) |  |  | (3) |
(Increase)/decrease in inventories | (3) |  |  | 10 |
(Increase)/decrease in margin deposits | 3 |  |  | (6) |
Increase/(decrease) in accounts payable and accrued liabilities | 61 |  |  | 24 |
Increase in margin deposits from wholesale counterparties | 102 |  |  | — |
Other working capital items, net | 22 |  |  | 27 |
Other, net | (65) |  |  | (46) |
Net cash provided by operating activities | 582 |  |  | 442 |

7

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

| Nine Months Ended September 30,
| 2021 |  | 2020
Cash flows from investing activities: |  |  |
Capital expenditures | (486) |  |  | (549) |
Sales of Nuclear decommissioning trust securities | 8 |  |  | 6 |
Purchases of Nuclear decommissioning trust securities | (6) |  |  | (5) |
Other, net | (18) |  |  | (3) |
Net cash used in investing activities | (502) |  |  | (551) |
Cash flows from financing activities: |  |  |
Proceeds from issuance of long-term debt | 400 |  |  | 319 |
Payments on long-term debt | (160) |  |  | (98) |
Borrowings on short-term debt | 200 |  |  | 275 |
Repayments of short-term debt | (350) |  |  | (50) |
Dividends paid | (112) |  |  | (103) |
Repurchase of common stock | (12) |  |  | — |
Other | (9) |  |  | (11) |
Net cash provided by (used in) financing activities | (43) |  |  | 332 |
Increase (Decrease) in cash and cash equivalents | 37 |  |  | 223 |
Cash and cash equivalents, beginning of period | 257 |  |  | 30 |
Cash and cash equivalents, end of period | $ | 294 |  |  | $ | 253 |
Supplemental cash flow information is as follows: |  |  |
Cash paid for interest, net of amounts capitalized | $ | 75 |  |  | $ | 70 |
Cash paid for income taxes | 16 |  |  | 9 |
See accompanying notes to condensed consolidated financial statements.

8

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1: BASIS OF PRESENTATION
Nature of Business
Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to provide reasonably-priced power for its retail customers. PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area encompasses 51 incorporated cities entirely within the State of Oregon. As of September 30, 2021, PGE served 914,000 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 nine months ended September 30, 2021 and 2020 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, 2020 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2020, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 19, 2021, which should be read in conjunction with the interim unaudited Financial Statements.
Comprehensive Income
No material change occurred in Other comprehensive income in the three and nine months ended September 30, 2021 and 2020.
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 electricity and natural gas, interim financial results do not necessarily represent those to be expected for the year.
9

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
NOTE 2: REVENUE RECOGNITION
Disaggregated Revenue
The following table presents PGE’s revenue, disaggregated by customer type (in millions):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Retail: |  |  |  |  |  |  |
Residential | $ | 265 |  |  | $ | 245 |  |  | $ | 824 |  |  | $ | 747 |
Commercial | 186 |  |  | 164 |  |  | 518 |  |  | 463 |
Industrial | 65 |  |  | 58 |  |  | 187 |  |  | 162 |
Direct access customers | 11 |  |  | 12 |  |  | 35 |  |  | 35 |
Subtotal | 527 |  |  | 479 |  |  | 1,564 |  |  | 1,407 |
Alternative revenue programs, net of amortization | (12) |  |  | (9) |  |  | (23) |  |  | — |
Other accrued revenues, net | 1 |  |  | 7 |  |  | 12 |  |  | 13 |
Total retail revenues | 516 |  |  | 477 |  |  | 1,553 |  |  | 1,420 |
Wholesale revenues* | 112 |  |  | 56 |  |  | 186 |  |  | 130 |
Other operating revenues | 14 |  |  | 14 |  |  | 49 |  |  | 39 |
Total revenues | $ | 642 |  |  | $ | 547 |  |  | $ | 1,788 |  |  | $ | 1,589 |

* Wholesale revenues include $37 million and $31 million related to electricity commodity contract derivative settlements for the three months ended September 30, 2021 and 2020, respectively, and $46 million and $55 million for the nine months ended September 30, 2021 and 2020, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, Risk Management.
Retail Revenues
The Company’s primary revenue source is the sale of electricity to customers at regulated, tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single-family housing, multiple-family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than residential customers. Commercial customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class.
In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and determined through general rate case proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options.
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Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that have not yet been billed to customers. This amount, classified as Unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.
PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. The Company applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, the Company 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 the Company’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and are not reflected in Revenues, net within the condensed consolidated statements of income and comprehensive income.
Wholesale Revenues
PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power; hydro, solar and wind conditions; and daily and seasonal retail demand.
PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.
Other Operating Revenues
Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers.
Arrangements with Multiple Performance Obligations
Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. The Company generally determines standalone selling prices based on the prices charged to customers.
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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, PGE assesses whether inventories are recorded at the lower of average cost or net realizable value.
Accounts Receivable, Net
Accounts receivable, net includes $80 million and $97 million of unbilled revenues as of September 30, 2021 and December 31, 2020, respectively. Accounts receivable, net is net of an allowance for credit losses of $27 million and $16 million as of September 30, 2021 and December 31, 2020, respectively. The following summarizes activity in the allowance for credit losses (in millions):

| Three Months Ended September 30, |  | Nine Months Ended September 30, |  |  |  |  |  |
| 2021 |  | 2021 |  |  |  |  |  |
Balance as of beginning of period | $ | 22 |  |  | $ | 16 |  |  |  |  |  |  |
Increase in provision | 11 |  |  | 26 |  |  |  |  |  |  |
Amounts written off | (7) |  |  | (19) |  |  |  |  |  |  |
Recoveries | 1 |  |  | 4 |  |  |  |  |  |  |
Balance as of end of period | $ | 27 |  |  | $ | 27 |  |  |  |  |  |  |

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

| September 30, 2021 |  | December 31, 2020
Prepaid expenses | $ | 44 |  |  | $ | 57 |
Assets from price risk management activities | 194 |  |  | 33 |
Margin deposits | 5 |  |  | 8 |
Other current assets | $ | 243 |  |  | $ | 98 |

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

| September 30, 2021 |  | December 31, 2020
Electric utility plant | $ | 11,334 |  |  | $ | 10,974 |
Construction work-in-progress | 503 |  |  | 429 |
Total cost | 11,837 |  |  | 11,403 |
Less: accumulated depreciation and amortization | (4,064) |  |  | (3,864) |
Electric utility plant, net | $ | 7,773 |  |  | $ | 7,539 |

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Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $432 million and $388 million as of September 30, 2021 and December 31, 2020, respectively. Amortization expense related to intangible assets was $44 million and $47 million for the nine months ended September 30, 2021 and 2020, respectively and $14 million and $16 million for the three months ended September 30, 2021 and 2020, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.
On June 30, 2021, PGE entered into a hydroelectric power purchase agreement (PPA) that later went into effect on October 19, 2021, after certain conditions precedent were met. The PPA will modify an existing operating lease by effectively extending the term of the lease from 2024 to 2040 and increasing the capacity payments in the extension period. In the fourth quarter, PGE will reclassify the lease from operating to finance, and the Company will record an additional lease liability and right-of-use (ROU) asset of approximately $140 million on PGE’s condensed consolidated balance sheets. The energy portion of the PPA is considered variable and will not be included in the calculation of the lease liability and right-of-use asset. Any material differences between expense recognition and timing of payments will be deferred as a regulatory asset or liability in order to match what is anticipated to be recovered in customer prices for ratemaking purposes.
Regulatory Assets and Liabilities
Regulatory assets and liabilities consist of the following (in millions):

| September 30, 2021 |  | December 31, 2020
| Current |  | Noncurrent |  | Current |  | Noncurrent
Regulatory assets: |  |  |  |  |  |  |
Price risk management | $ | — |  |  | $ | 11 |  |  | $ | — |  |  | $ | 124 |
Pension and other postretirement plans | — |  |  | 223 |  |  | — |  |  | 240 |
Debt issuance costs | — |  |  | 24 |  |  | — |  |  | 25 |
Trojan decommissioning activities | — |  |  | 99 |  |  | — |  |  | 95 |
Incremental storm costs | — |  |  | 58 |  |  | — |  |  | — |
Power cost adjustment mechanism | — |  |  | 27 |  |  | — |  |  | — |
Wildfire | — |  |  | 36 |  |  | — |  |  | 15 |
COVID-19 | — |  |  | 27 |  |  | — |  |  | 10 |
Other | 14 |  |  | 62 |  |  | 23 |  |  | 60 |
Total regulatory assets | $ | 14 |  |  | $ | 567 |  |  | $ | 23 |  |  | $ | 569 |
Regulatory liabilities: |  |  |  |  |  |  |
Asset retirement removal costs | $ | — |  |  | $ | 1,035 |  |  | $ | — |  |  | $ | 1,016 |
Deferred income taxes | — |  |  | 213 |  |  | — |  |  | 239 |
Asset retirement obligations | — |  |  | 54 |  |  | — |  |  | 37 |
Price risk management | 155 |  |  | — |  |  | 18 |  |  | — |
Other | 32 |  |  | 68 |  |  | 5 |  |  | 77 |
Total regulatory liabilities | $ | 187 |  | * | $ | 1,370 |  |  | $ | 23 |  | * | $ | 1,369 |

* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.
Incremental storm costs represent the costs not previously included for recovery in customer prices related to major storm damage incurred during the nine months ended September 30, 2021. Such costs were incurred to repair damage to PGE’s transmission and distribution systems and restore power to customers as a result of the historic
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storms that ultimately led Oregon’s Governor to declare a state of emergency on February 13, 2021. On February 15, 2021, the Company filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156). PGE does not expect an OPUC decision on the February storm deferral until 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery and their conclusions of overall prudence, including an earnings review, and could result in a portion, or all, of PGE’s deferral being disallowed for recovery.
Power Cost Adjustment Mechanism—PGE is subject to a Power Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s condensed consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the condensed consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For the nine months ended September 30, 2021, actual NVPC was $60 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be above the baseline, and outside the established deadband range. Pursuant to the PCAM and related earnings test, as of September 30, 2021, PGE has deferred $27 million which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, and could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Wildfire—In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned that ultimately led Oregon’s Governor to declare a state of emergency on August 20, 2020. As a result, PGE has incurred costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. Ongoing costs include replacing equipment, enhanced tree and brush clearing, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a public safety power shutoff (PSPS), if the need should arise. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs (Docket UM 2115). As of September 30, 2021 and December 31, 2020, PGE’s cumulative deferred costs related to the wildfire response was $36 million and $15 million, respectively. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. PGE believes the full amount of the 2020 and 2021 deferrals is probable of recovery as the Company’s prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
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COVID-19 Impacts—The COVID-19 pandemic led Oregon’s Governor to declare a state of emergency on March 8, 2020 and is still in effect. Due to the adverse impacts of COVID-19 on economic activity, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs. On March 20, 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities which may qualify for deferral under Docket UM2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of September 30, 2021 and December 31, 2020, PGE’s deferred balance was $27 million and $10 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test. PGE believes the full amount of the 2020 and 2021 deferrals is probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consist of the following (in millions):

| September 30, 2021 |  | December 31, 2020
Accrued employee compensation and benefits | $ | 65 |  |  | $ | 67 |
Accrued taxes payable | 58 |  |  | 36 |
Accrued interest payable | 42 |  |  | 29 |
Accrued dividends payable | 40 |  |  | 38 |
Regulatory liabilities—current | 187 |  |  | 23 |
Margin deposits from wholesale counterparties | 102 |  |  | — |
Other | 117 |  |  | 129 |
Total accrued expenses and other current liabilities | $ | 611 |  |  | $ | 322 |

Credit Facilities
On September 10, 2021, PGE amended and restated its existing revolving credit facility. As of September 30, 2021, PGE had a $650 million revolving credit facility scheduled to expire in September 2026. The Company has the ability to expand the revolving credit facility to $750 million, if needed. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, 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 the Company’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of September 30, 2021, PGE was in compliance with this covenant with a 56.4% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $650 million. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on
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PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. The Company believes these potential adjustments will have an immaterial impact on PGE’s results of operations.
The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. 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. As of September 30, 2021, PGE had no commercial paper outstanding.
PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.
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 $78 million were outstanding as of September 30, 2021. 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 bore interest for the relevant interest period at LIBOR plus 1.25%. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 31, 2021, this term loan was repaid in full with proceeds from the subsequent term loan described below.
On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan bore interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to terms of the loan. The credit agreement was set to expire on March 30, 2022, with any outstanding balance due and payable on such date. The term loan was paid off early on September 30, 2021 with proceeds from a first mortgage bond issuance.
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 6, 2022.
Long-term Debt
On January 6, 2021, the Company made a scheduled $140 million repayment of a 2.51% Series of First Mortgage Bonds with available cash.
On August 11, 2021, the Company made a scheduled $20 million repayment of a 9.31% Series of First Mortgage Bonds with available cash.
On September 30, 2021, PGE issued $400 million in First Mortgage Bonds (FMBs). The Bonds consist of:
•a series, due in 2028 (the "2028 Bonds"), in the amount of $100 million that will bear an interest from its issuance date at an annual rate of 1.82%;
•a series, due in 2031 (the “2031 Bonds"), in the amount of $50 million that will bear an interest from its issuance date at an annual rate of 2.10%;
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•a series, due in 2034 (the "2034 Bonds" and collectively with the 2028 Bonds and the 2031 Bonds, the "Other Bonds"), in the amount of $100 million that will bear an interest from its issuance date at an annual rate of 2.20%; and
•a series, due in 2051, (the "2051 Bonds") in the amount of $150 million that will bear an interest from its issuance date at an annual rate of 2.97%.
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,
| 2021 |  | 2020 |  | 2021 |  | 2020
Service cost | $ | 5 |  |  | $ | 4 |  |  | $ | 15 |  |  | $ | 12 |
Interest cost* | 6 |  |  | 8 |  |  | 20 |  |  | 24 |
Expected return on plan assets* | (12) |  |  | (11) |  |  | (34) |  |  | (33) |
Amortization of net actuarial loss* | 6 |  |  | 4 |  |  | 16 |  |  | 12 |
Net periodic benefit cost | $ | 5 |  |  | $ | 5 |  |  | $ | 17 |  |  | $ | 15 |

* The net expense portion of non-service cost components are included in Miscellaneous income (expense), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.
NOTE 4: FAIR VALUE OF FINANCIAL INSTRUMENTS
PGE estimated the fair value of financial asset and liability instruments as of September 30, 2021 and December 31, 2020, and classified these financial instruments based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are:

Level 1 | Quoted prices are available in active markets for identical assets or liabilities as of the measurement date;
Level 2 | Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date; and
Level 3 | Pricing inputs include significant inputs that are unobservable for the asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of 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.
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.
The Company’s financial assets and liabilities whose values were recognized at fair value in the Company’s condensed consolidated balance sheets are as follows by level within the fair value hierarchy (in millions):
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| As of September 30, 2021
| Level 1 |  | Level 2 |  | Level 3 |  | Other(2) |  | Total
Assets: |  |  |  |  |  |  |  |  |
Cash equivalents | $ | 42 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 42 |
Nuclear decommissioning trust: (1) |  |  |  |  |  |  |  |  |
Debt securities: |  |  |  |  |  |  |  |  |
Domestic government | 10 |  |  | 8 |  |  | — |  |  | — |  |  | 18 |
Corporate credit | — |  |  | 13 |  |  | — |  |  | — |  |  | 13 |
Money market funds measured at NAV (2) | — |  |  | — |  |  | — |  |  | 12 |  |  | 12 |
Non-qualified benefit plan trust: (3) |  |  |  |  |  |  |  |  |
Debt securities—domestic government | — |  |  | — |  |  | — |  |  | — |  |  | — |
Money market funds | 2 |  |  | — |  |  | — |  |  | — |  |  | 2 |
Equity securities | 7 |  |  | — |  |  | — |  |  | — |  |  | 7 |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | — |  |  | 31 |  |  | 12 |  |  | — |  |  | 43 |
Natural gas | — |  |  | 205 |  |  | 24 |  |  | — |  |  | 229 |
| $ | 61 |  |  | $ | 257 |  |  | $ | 36 |  |  | $ | 12 |  |  | $ | 366 |
Liabilities: |  |  |  |  |  |  |  |  |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 36 |  |  | $ | 90 |  |  | $ | — |  |  | $ | 126 |
Natural gas | — |  |  | 2 |  |  | — |  |  | — |  |  | 2 |
| $ | — |  |  | $ | 38 |  |  | $ | 90 |  |  | $ | — |  |  | $ | 128 |

(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 $35 million, which are recorded at cash surrender value.
(4)For further information, see Note 5, Risk Management.
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| As of December 31, 2020
| Level 1 |  | Level 2 |  | Level 3 |  | Other (2) |  | Total
Assets: |  |  |  |  |  |  |  |  |
Cash equivalents | $ | 255 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 255 |
Nuclear decommissioning trust: (1) |  |  |  |  |  |  |  |  |
Debt securities: |  |  |  |  |  |  |  |  |
Domestic government | 9 |  |  | 11 |  |  | — |  |  | — |  |  | 20 |
Corporate credit | — |  |  | 13 |  |  | — |  |  | — |  |  | 13 |
Money market funds measured at NAV (2) | — |  |  | — |  |  | — |  |  | 12 |  |  | 12 |
Non-qualified benefit plan trust: (3) |  |  |  |  |  |  |  |  |
Debt securities—domestic government | 1 |  |  | — |  |  | — |  |  | — |  |  | 1 |
Money market funds | 1 |  |  | — |  |  | — |  |  | — |  |  | 1 |
Equity securities | 7 |  |  | — |  |  | — |  |  | — |  |  | 7 |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | — |  |  | 4 |  |  | 4 |  |  | — |  |  | 8 |
Natural gas | — |  |  | 36 |  |  | 1 |  |  | — |  |  | 37 |
| $ | 273 |  |  | $ | 64 |  |  | $ | 5 |  |  | $ | 12 |  |  | $ | 354 |
Liabilities: |  |  |  |  |  |  |  |  |
Price risk management activities: (1) (4) |  |  |  |  |  |  |  |  |
Electricity | $ | — |  |  | $ | 5 |  |  | $ | 141 |  |  | $ | — |  |  | $ | 146 |
Natural gas | — |  |  | 4 |  |  | 1 |  |  | — |  |  | 5 |
| $ | — |  |  | $ | 9 |  |  | $ | 142 |  |  | $ | — |  |  | $ | 151 |

(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 $33 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 not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. Cash equivalents are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (Nasdaq) and the New York Stock Exchange (NYSE).
Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:
Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.
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(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.
Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Risk Management.
For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.
Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer-term commodity forwards, futures, and swaps.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:

|  | Fair Value |  | Valuation Technique |  | Significant Unobservable Input |  | Price per Unit
Commodity Contracts |  | Assets |  | Liabilities |  |  |  | Low |  | High |  | Weighted Average
|  | (in millions) |  |  |  |  |  |  |  |  |  |
As of September 30, 2021 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity physical forwards |  | $ | 4 |  |  | $ | 90 |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | $ | 15.00 |  |  | $ | 127.00 |  |  | $ | 47.86 |
Natural gas financial swaps |  | 24 |  |  | — |  |  | Discounted cash flow |  | Natural gas forward price (per Decatherm) |  | 2.21 |  |  | 8.12 |  |  | 3.23 |
Electricity financial futures |  | 8 |  |  | — |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | 26.50 |  |  | 71.00 |  |  | 56.45 |
|  | $ | 36 |  |  | $ | 90 |  |  |  |  |  |  |  |  |  |  |
As of December 31, 2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity physical forwards |  | $ | — |  |  | $ | 141 |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | $ | 11.17 |  |  | $ | 51.18 |  |  | $ | 29.74 |
Natural gas financial swaps |  | 1 |  |  | 1 |  |  | Discounted cash flow |  | Natural gas forward price (per Decatherm) |  | 1.52 |  |  | 4.33 |  |  | 2.29 |
Electricity financial futures |  | 4 |  |  | — |  |  | Discounted cash flow |  | Electricity forward price (per MWh) |  | 8.78 |  |  | 58.42 |  |  | 43.71 |
|  | $ | 5 |  |  | $ | 142 |  |  |  |  |  |  |  |  |  |  |

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 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 that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices.
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 Input |  | Position |  | Change to Input |  | Impact on Fair Value
Market price |  | Buy |  | Increase (decrease) |  | Gain (loss)
Market price |  | Sell |  | Increase (decrease) |  | Loss (gain)

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Balance as of the beginning of the period | $ | 58 |  |  | $ | 151 |  |  | $ | 137 |  |  | $ | 97 |
Net realized and unrealized losses/(gains)* | 11 |  |  | (17) |  |  | (72) |  |  | 39 |
Transfers from Level 3 to Level 2 | (15) |  |  | — |  |  | (11) |  |  | (2) |
Balance as of the end of the period | $ | 54 |  |  | $ | 134 |  |  | $ | 54 |  |  | $ | 134 |

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
* Both realized and unrealized losses/(gains), of which unrealized portion are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income. Includes $2 million in net realized losses and $5 million in net realized gains for the three-month periods ended September 30, 2021 and September 30, 2020, respectively. For the nine-month periods ended September 30, 2021 and September 30, 2020, includes $4 million in net realized losses and $8 million in net realized gains, respectively.
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.
Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s FMBs and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.
As of September 30, 2021, the carrying amount of PGE’s long-term debt was $3,285 million, net of $14 million of unamortized debt expense, and its estimated aggregate fair value was $3,854 million. As of December 31, 2020, the carrying amount of PGE’s long-term debt was $3,046 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,808 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 forwards, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with the ratemaking and cost recovery processes authorized by the 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 ins truments as economic hedges. The Company does not intend to engage in trading activities for non-retail purposes.
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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, 2021 |  | December 31, 2020 |
Current assets: |  |  |  |
Commodity contracts: |  |  |  |
Electricity | $ | 34 |  |  | $ | 4 |  |
Natural gas | 160 |  |  | 29 |  |
Total current derivative assets(1) | 194 |  |  | 33 |  |
Noncurrent assets: |  |  |  |
Commodity contracts: |  |  |  |
Electricity | 9 |  |  | 4 |  |
Natural gas | 69 |  |  | 8 |  |
Total noncurrent derivative assets(1) | 78 |  |  | 12 |  |
Total derivative assets(2) | $ | 272 |  |  | $ | 45 |  |
Current liabilities: |  |  |  |
Commodity contracts: |  |  |  |
Electricity | $ | 37 |  |  | $ | 13 |  |
Natural gas | 2 |  |  | 2 |  |
Total current derivative liabilities | 39 |  |  | 15 |  |
Noncurrent liabilities: |  |  |  |
Commodity contracts: |  |  |  |
Electricity | 89 |  |  | 133 |  |
Natural gas | — |  |  | 3 |  |
Total noncurrent derivative liabilities | 89 |  |  | 136 |  |
Total derivative liabilities(2) | $ | 128 |  |  | $ | 151 |  |

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.
(2) As of September 30, 2021 and December 31, 2020, no derivative assets or liabilities were designated as hedging instruments.
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, 2021 |  | December 31, 2020
Commodity contracts: |  |  |  |  |
Electricity | 4 |  | MWhs |  | 6 |  | MWhs
Natural gas | 173 |  | Decatherms |  | 137 |  | Decatherms
Foreign currency | $ | 17 |  | Canadian |  | $ | 19 |  | 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,
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
such as letters of credit. As of September 30, 2021 and December 31, 2020, gross amounts included as Price risk management liabilities subject to master netting agreements was an immaterial amount.
Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, 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,
| 2021 |  | 2020 |  | 2021 |  | 2020
Commodity contracts: |  |  |  |  |  |  |
Electricity | $ | 11 |  |  | $ | 113 |  |  | $ | (56) |  |  | $ | 160 |
Natural Gas | (142) |  |  | (47) |  |  | (256) |  |  | (51) |
Foreign currency exchange | — |  |  | (1) |  |  | — |  |  | — |

Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended September 30, 2021 and 2020, ne t gains o f $114 million and net gains of $63 million, respectively, have been offset. Net gains of $265 million and net gains of $22 million have been offset for the nine-month periods ended September 30, 2021 and 2020, respectively.
Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of September 30, 2021 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

| 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025 |  | Thereafter |  | Total
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |
Electricity | $ | (10) |  |  | $ | 7 |  |  | $ | 2 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | 74 |  |  | $ | 83 |
Natural gas | (58) |  |  | (125) |  |  | (37) |  |  | (6) |  |  | (1) |  |  | — |  |  | (227) |
Net unrealized loss/(gain) | $ | (68) |  |  | $ | (118) |  |  | $ | (35) |  |  | $ | (1) |  |  | $ | 4 |  |  | $ | 74 |  |  | $ | (144) |

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.
The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of September 30, 2021 was $118 million, for which PGE has posted $23 million in collateral, consisting of $20 million of letters of credit and $3 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2021, the cash requirement to either post as collateral or settle the instruments immediately would have been $112 million. As of September 30, 2021, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheets.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
As of September 30, 2021, PGE received from counterparties $110 million in collateral, consisting of $8 million of letters of credit and $102 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.
Counterparties representing 10% or more of assets and liabilities from price risk management activities were as follows:

| September 30, 2021 |  | December 31, 2020
Assets from price risk management activities: |  |  |
Counterparty A | 13 | % |  | 12 | %
Counterparty B | 12 |  |  | 17 |
Counterparty C | 27 |  |  | 21 |
Counterparty D | 8 |  |  | 16 |
Counterparty E | 11 |  |  | 8 |
Counterparty F | 12 |  |  | 5 |
| 83 | % |  | 79 | %
Liabilities from price risk management activities: |  |  |
Counterparty G | 69 | % |  | 93 | %
Counterparty H | 11 |  |  | — |
| 80 | % |  | 93 | %

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.
NOTE 6: EARNINGS PER SHARE
Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.
For the three and nine months ended September 30, 2021, unvested performance-based restricted stock units and related dividend equivalent rights of 365 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 302 thousand shares excluded for the three and nine months ended September 30, 2020.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)
Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Weighted-average common shares outstanding—basic | 89,407 |  |  | 89,509 |  |  | 89,505 |  |  | 89,476 |
Dilutive effect of potential common shares | 159 |  |  | — |  |  | 141 |  |  | 153 |
Weighted-average common shares outstanding—diluted | 89,566 |  |  | 89,509 |  |  | 89,646 |  |  | 89,629 |

NOTE 7: SHAREHOLDERS’ EQUITY
The activity in equity during the three- and nine-month periods ended September 30, 2021 and 2020 was as follows (dollars in millions, except per share amounts):

| Common Stock |  | Accumulated Other Comprehensive Loss |  | Retained Earnings |  |  |  |  |
| Shares |  | Amount |  |  |  | Total |  |
Balances as of December 31, 2020 | 89,537,331 |  |  | $ | 1,231 |  |  | $ | (11) |  |  | $ | 1,393 |  |  | $ | 2,613 |  |  |  |
Issuances of shares pursuant to equity-based plans | 39,417 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Stock-based compensation | — |  |  | 2 |  |  | — |  |  | — |  |  | 2 |  |  |  |
Dividends declared ($0.4075 per share) | — |  |  | — |  |  | — |  |  | (36) |  |  | (36) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 96 |  |  | 96 |  |  |  |
Balances as of March 31, 2021 | 89,576,748 |  |  | $ | 1,233 |  |  | $ | (11) |  |  | $ | 1,453 |  |  | $ | 2,675 |  |  |  |
Issuances of shares pursuant to equity-based plans | 74,974 |  |  | 1 |  |  | — |  |  | — |  |  | 1 |  |  |  |
Stock-based compensation | — |  |  | 4 |  |  | — |  |  | — |  |  | 4 |  |  |  |
Repurchase of common stock | (250,000) |  |  | (3) |  |  | — |  |  | (9) |  |  | (12) |  |  |  |
Dividends declared ($0.4300 per share) | — |  |  | — |  |  | — |  |  | (39) |  |  | (39) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 32 |  |  | 32 |  |  |  |
Balances as of June 30, 2021 | 89,401,722 |  |  | $ | 1,235 |  |  | $ | (11) |  |  | $ | 1,437 |  |  | $ | 2,661 |  |  |  |
Issuances of shares pursuant to equity-based plans | 7,290 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Stock-based compensation | — |  |  | 2 |  |  | — |  |  | — |  |  | 2 |  |  |  |
Other comprehensive income | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |  |  |  |
Dividends declared ($0.4300 per share) | — |  |  | — |  |  | — |  |  | (39) |  |  | (39) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 50 |  |  | 50 |  |  |  |
Balances as of September 30, 2021 | 89,409,012 |  |  | $ | 1,237 |  |  | $ | (10) |  |  | $ | 1,448 |  |  | $ | 2,675 |  |  |  |

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)

| Common Stock |  | Accumulated Other Comprehensive Loss |  | Retained Earnings |  |  |  |  |
| Shares |  | Amount |  |  |  | Total |  |  |
Balances as of December 31, 2019 | 89,387,124 |  |  | $ | 1,220 |  |  | $ | (10) |  |  | $ | 1,381 |  |  | $ | 2,591 |  |  |  |
Issuances of shares pursuant to equity-based plans | 77,397 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Other comprehensive income | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |  |  |  |
Dividends declared ($0.3850 per share) | — |  |  | — |  |  | — |  |  | (35) |  |  | (35) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 81 |  |  | 81 |  |  |  |
Balances as of March 31, 2020 | 89,464,521 |  |  | $ | 1,220 |  |  | $ | (9) |  |  | $ | 1,427 |  |  | $ | 2,638 |  |  |  |
Issuances of shares pursuant to equity-based plans | 42,430 |  |  | 1 |  |  | — |  |  | — |  |  | 1 |  |  |  |
Stock-based compensation | — |  |  | 3 |  |  | — |  |  | — |  |  | 3 |  |  |  |
Dividends declared ($0.3850 per share) | — |  |  | — |  |  | — |  |  | (35) |  |  | (35) |  |  |  |
Net income | — |  |  | — |  |  | — |  |  | 39 |  |  | 39 |  |  |  |
Balances as of June 30, 2020 | 89,506,951 |  |  | $ | 1,224 |  |  | $ | (9) |  |  | $ | 1,431 |  |  | $ | 2,646 |  |  |  |
Issuances of shares pursuant to equity-based plans | 2,832 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |
Stock-based compensation | — |  |  | 2 |  |  | — |  |  | — |  |  | 2 |  |  |  |
Dividends declared ($0.4075 per share) | — |  |  | — |  |  | — |  |  | (36) |  |  | (36) |  |  |  |
Net income (loss) | — |  |  | — |  |  | — |  |  | (17) |  |  | (17) |  |  |  |
Balances as of September 30, 2020 | 89,509,783 |  |  | $ | 1,226 |  |  | $ | (9) |  |  | $ | 1,378 |  |  | $ | 2,595 |  |  |  |

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 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.
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(Unaudited)
If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event.
PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
EPA Investigation of Portland Harbor
An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river.
A Portland Harbor site remedial investigation was completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.
The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor, which has an undiscounted estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs. 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. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. 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 Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain
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PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has indicated it will take the initial lead to perform remedial design on the remaining areas. The Company anticipates that remedial design costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy. The EPA announced on February 12, 2021 that the entirety of Portland Harbor is under an active engineering design phase.
PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including conclusion of remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor 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 (CTWS), 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 costs related to EPA and NRD liabilities on the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC in 2017, the PHERA allows the Company to defer and recover incurred estimated liabilities and environmental expenditures related to Portland Harbor through a combination of third-party proceeds, including but not limited to 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.
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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 under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleged the violations were related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.
The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements, for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA alleged that PGE’s operation of the SWW had caused the above-referenced violations of the CWA, which in turn had degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters.
In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and CTWS, which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the Court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant.
In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case.
In October 2018, DRA filed an appeal, and PGE and the CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. The appeals were fully briefed and oral argument occurred. On June 23, 2021, the Ninth Circuit Court of Appeals issued a decision to dismiss the case.
Securities Case
During September and October, 2020, three putative class action complaints were filed in U.S. District Court for the District of Oregon against PGE and certain of its officers, captioned Hessel v. Portland General Electric Co., No. 20-cv-01523 (“Hessel”), Cannataro v. Portland General Electric Co., No. 3:20-cv-01583 (“Cannataro”), and Public Employees’ Retirement System of Mississippi v. Portland General Electric Co., No. 20-cv-01786 (“PERS of Mississippi”). Two of these actions were filed on behalf of purported purchasers of PGE stock between April 24, 2020, and August 24, 2020; a third action was filed on behalf of purported purchasers of PGE stock between February 13, 2020, and August 24, 2020.
During the fourth quarter of 2020, the plaintiff in Hessel voluntarily dismissed his case and the Court consolidated Cannataro and PERS of Mississippi into a single case captioned In re Portland General Electric Company Securities Litigation (the “Securities Action”) and appointed Public Employees’ Retirement System of Mississippi lead plaintiff (“Lead Plaintiff”). On January 11, 2021, Lead Plaintiff filed an amended complaint asserting causes of action arising under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 for alleged misstatements and omissions regarding, among other things, PGE’s alleged lack of sufficient internal controls and risks associated with PGE's trading activity in wholesale electric markets, purportedly on behalf of purchasers of PGE stock between
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February 13, 2020, and August 24, 2020 (“the Amended Complaint”). The Amended Complaint demands a jury trial and seeks compensatory damages of an unspecified amount and reimbursement of plaintiffs’ costs, and attorneys’ and expert fees. On March 12, 2021, the defendants filed a motion to dismiss the Amended Complaint.
On July 11, 2021, the parties entered into a Stipulation of Settlement (the "Agreement") to fully resolve the Securities Action. The Agreement, which is subject to Court approval, provides for a settlement payment of $6.75 million in exchange for the complete dismissal with prejudice and a release of all claims against the defendants in connection with the Securities Action, without any admission of fault or wrongdoing by the defendants. On July 16, 2021, the Lead Plaintiff filed an application for Court approval of the settlement. In an order dated August 10, 2021, the Court granted preliminary approval of the settlement, stayed all proceedings in the action except with respect to settlement, and scheduled a final settlement approval hearing for March 11, 2022. The settlement payment was paid by the Company’s insurance provider under its insurance policy. In light of the Agreement, the Court removed the hearing on the defendants’ pending motion to dismiss from the calendar.
Putative Shareholder Derivative Lawsuits
On January 26, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned Shimberg v. Pope, No. 21- cv-02957, (the “Shimberg Action”) against one current and one former PGE executive and certain members and former members of the Company's Board of Directors (collectively, the "Individual Defendants") and naming the Company as a nominal defendant only. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the Individual Defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks damages to be awarded to the Company of not less than $10 million, equitable relief to remedy the alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. The Court has entered an order staying the Shimberg Action until November 30, 2021, or until further order of the Court reinstating the action. On June 1, 2021, the plaintiff filed an unopposed motion to consolidate this lawsuit with the Ashabraner Action (described below), which the Court granted in an order dated July 27, 2021. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.
On March 17, 2021, a putative shareholder derivative lawsuit was filed in U.S. District Court for the District of Oregon, captioned JS Halberstam Irrevocable Grantor Trust v. Davis, No. 3:21-cv-00413-SI, against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserts claims for alleged breaches of fiduciary duties, waste of corporate assets, contribution and indemnification, aiding and abetting, and gross mismanagement, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demands a jury trial and seeks equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. The Court has entered an order staying the action until November 30, 2021, and setting a deadline of December 1, 2021, for parties to submit a joint status report. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.
On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope, 21-cv-13698 the “Ashabraner Action”), against one current and one former PGE executive and certain and former members of the Company's Board of Directors. The plaintiff asserts a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleges that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint
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demands a jury trial and seeks damages to be awarded to the Company, equitable relief, and an award of plaintiff’s attorneys’ fees and costs. On July 27, 2021, the Court issued an order consolidating the Ashabraner Action with the Shimberg Action. The Court has entered an order staying Ashabraner Action until November 30, 2021. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.
On May 21, 2021, a putative shareholder derivative lawsuit was filed in the U.S. District Court for the District of Oregon, Portland Division captioned Berning v. Pope, No. 3:21-cv-00783-SI, against one current and one former PGE executive and certain current and former members of the Company's Board of Directors and naming the Company as a nominal defendant only. The plaintiff asserts claims for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff also asserts a claim against the two executives for contribution and indemnity based on alleged violations of Sections 10(b) and 21D of the Exchange Act. The complaint demands a jury trial and seeks multiple forms of relief, including, among other things: a declaration that defendants breached and/or aided and abetted the breach of their fiduciary duties to PGE; an order directing PGE to reform and improve its corporate governance and internal procedures; restitution; and an award of attorneys’ fees, expenses, and costs. Since the lawsuit is in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible loss.
Governmental Investigations
In March, April and May 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC"), the Division of Enforcement of the SEC, and the Division of Enforcement of the Federal Energy Regulatory Commission ("FERC"), respectively, informed the Company they are conducting investigations arising out of the energy trading losses the Company previously announced in August 2020. The Company is cooperating with the CFTC, SEC, and FERC. Management cannot at this time predict the eventual scope or outcome of these matters.
Colstrip Litigation
The Company has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is operated by one of the co-owners, Talen Montana, LLC (Talen). Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. In addition, other parties have brought claims against the co-owners, which, along with the co-owner disagreements, are described below.
Petition to compel arbitration—On April 12, 2021, Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and Portland General Electric Company (the Petitioners) petitioned in Spokane County Superior Court, Washington. Case No. 21201000-32, against NorthWestern Corporation and Talen to compel the arbitration initiated by NorthWestern Corporation to determine whether owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or whether unanimous consent is required. The O&O Agreement among the parties states that any dispute shall be submitted for resolution to a single arbitrator with appropriate expertise. On April 14, 2021, the Petitioners filed a petition to compel arbitration. On May 14, 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Talen filed a motion, which, following a hearing in July 2021, was granted, to transfer the case to the U.S. District Court for the District of Montana. Petitioners filed a motion to remand on June 4, 2021.
Challenge to constitutionality of Montana Senate Bills 265 and 266 (SB 265 and SB 266)—On May 4, 2021, the Petitioners filed a claim against NorthWestern Corporation and Talen in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of SB 265 in Montana, which attempts to void
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contractual provisions within the co-owner agreement for Colstrip if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. The passage of SB 265 was supported by Defendants and purports to void the O&O Agreement between all parties, which provides for one arbitrator and venue in Spokane, Washington. The petitioners allege that SB 265 violates the contracts clause of the U.S. Constitution and the Montana Constitution, and is preempted by the Federal Arbitration Act (FAA). The Petitioners seek declaratory relief that SB 265 is unconstitutional as applied to the O&O Agreement and the FAA preempts the enforcement of SB 265.
Petitioners filed a First Amended Complaint on May 19, 2021, adding the Attorney General of Montana (Montana AG) as defendant and challenging the constitutionality of Montana Senate Bill 266 (SB 266), which purportedly gives the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, or otherwise fails to pay the costs to maintain the plant. Defendant Northwestern filed an answer on June 2, 2021 and asked tha t the case Talen filed, as described in the “Complaint to implement SB 265 and SB 266” below, and this case be consolidated. On May 27, 2021, Petitioners filed a Motion for Preliminary Injunction, to enjoin the Montana AG from enforcing SB 266 against them. On June 17, 2021, d efendants NorthWestern Corporation and Talen filed their Oppositions to Motion for Preliminary Injunction (PI) and the Montana AG filed a response taking no position on the PI, stating the State of Montana does not envision enforcing SB 266 any time soon. The Court held a hearing on the Petitioners’ Motion for PI August 6, 2021. On October 13, 2021, the Court issued an order that granted the Petitioners’ Motion for PI, enjoining the Montana AG from enforcing SB 266 against them.
On August 17, 2021, the Petitioners filed for partial summary judgment on their claim to declare unconstitutional or unenforceable SB 265, which purports to invalidate the arbitration provision of the parties’ contract. Talen opposes the motion and Northwestern does not oppose the motion, but requests the Court compel arbitration.
Complaint to implement SB 265 and SB 266—On May 4, 2021, Talen filed a complaint against the Petitioners and NorthWestern Corporation, in the Thirteenth Judicial District Court in the State of Montana, as an attempt to implement Montana laws when determining the language of the O&O agreement based on the recent enactment of SB 265, which purports to invalidate provisions of the co-owner operating agreement regarding arbitration, and SB 266, which purports to give the Montana AG authority to prosecute and levy a $100,000 a day fine against any co-owner who takes steps to close Colstrip without unanimous consent of all co-owners. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. Talen filed a motion to remand the case to the State of Montana District Court. Petitioners and NorthWestern have filed a motion to consolidate this case with the Challenge to constitutionality of Montana Senate Bills 265 and 266, described above. On October 21, 2022, the Court stayed the motion to consolidate pending the outcome of Talen’s petition to remand.
Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. On December 14, 2020, the original claim was filed in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from the defendants coal dust. On August 26, 2021, the claim was amended to add PGE as a defendant. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court.
Since these lawsuits are in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible losses.
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
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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 that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of September 30, 2021, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.
NOTE 10: INCOME TAXES
Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The change from pre-tax book loss for the three months ended September 30, 2020 to pre-tax book income for the three months ended September 30, 2021 is the primary driver for the change in interim effective tax rate results. The significant differences between the U.S. Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Federal statutory tax rate | 21.0 | % |  | 21.0 | % |  | 21.0 | % |  | 21.0 | %
Federal tax credits* | (11.2) |  |  | 14.8 |  |  | (10.1) |  |  | (23.6) |
State and local taxes, net of federal tax benefit | 8.9 |  |  | 4.2 |  |  | 8.7 |  |  | 10.4 |
Flow-through depreciation and cost basis differences | (1.5) |  |  | 17.5 |  |  | (1.0) |  |  | (7.2) |
Amortization of excess deferred income tax | (4.6) |  |  | (0.4) |  |  | (3.7) |  |  | (2.8) |
Local tax flow-through adjustment | — |  |  | — |  |  | (4.2) |  |  | — |
Other | (3.5) |  |  | 4.3 |  |  | (1.5) |  |  | (1.8) |
Effective tax rate | 9.1 | % |  | 61.4 | % |  | 9.2 | % |  | (4.0) | %

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030.
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Local tax flow-through adjustment
The Company is subject to a local tax that is recovered through a supplemental tariff based on current tax expense, but for which the Company has also recognized deferred income tax expenses over time. Because it is probable that the local deferred taxes will be flowed through future customer prices in accordance with the supplemental tariff, PGE determined a corresponding regulatory asset should have been recorded. In the first quarter of 2021, PGE recognized a regulatory asset to defer previously recorded deferred income tax expenses in the amount of $9 million with a corresponding credit to Income tax expense reflected in the condensed consolidated statements of income for the nine months ended September 30, 2021. The adjustment has no impact to the three months ended September 30, 2021, and is immaterial to prior-year periods.
Carryforwards
Federal tax credit carryforwards as of September 30, 2021 and December 31, 2020 were $98 million and $77 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2041. PGE believes that it is more likely than not that its deferred income tax assets as of September 30, 2021 will be realized; accordingly, no valuation allowance has been recorded. As of September 30, 2021, and December 31, 2020, PGE had no material unrecognized tax benefits.
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Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Statements
The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, 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 expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished.
In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:
•governmental policies, legislative action, and regulatory audits, investigations, and actions, including those of the FERC and 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, operating expenses, timely recovery of costs, and capital investments, and current or prospective wholesale and retail competition;
•economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers, and elevated levels of uncollectible customer accounts;
•changing customer expectations and choices that may reduce customer demand for its services may impact PGE’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators;
•the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements;
•natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability;
•unseasonable or extreme weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, PGE’s ability to access the wholesale energy market, PGE’s ability to operate its generating facilities and transmission and distribution systems, the Company’s costs to maintain, repair, and replace such facilities and systems, and recovery of costs;
•PGE’s ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk;
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•operational factors affecting PGE’s power generating facilities and battery storage facilities, including forced outages, unscheduled delays, 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 plant, 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;
•failure to complete capital projects on schedule and within budget, failure of counterparties to perform under agreements, or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
•volatility in wholesale power and natural gas prices that could require PGE to post additional collateral or issue additional letters of credit 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, cause damage to PGE facilities and system, or adversely affect its operations;
•changes in residential, commercial, or industrial customer demand, or demographic patterns, in PGE’s service territory;
•the effectiveness of PGE’s risk management policies and procedures;
•cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, employee, or Company information;
•employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and the ability to recruit and retain appropriate talent;
•new federal, state, and local laws that could have adverse effects on operating results;
•failure to achieve the Company’s greenhouse gas emission goals or be perceived to have either failed to act responsibly with respect to the environment or to effectively respond to legislative requirements concerning greenhouse gas emission reductions can lead to adverse publicity and could have adverse effects on the Company's operations and/or damage the Company's reputation;
•political and economic conditions;
•the impact of widespread health developments, including the global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other
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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.
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. The MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, 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 in the state of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.
Company Strategy
PGE remains committed to achieving 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 (GHG) 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 plans to:
•Decarbonize the power supply by reducing GHG emissions associated with the power served to customers by at least 80% by 2030, and achieving zero GHG emissions associated with the power served to customers by 2040;
•Electrify other sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and
•Perform by improving work efficiency, safety of our coworkers, and reliability of our systems and equipment, all while adhering to the Company’s earnings per diluted share growth guidance of 4-6% on average.
Decarbonize the power supply—PGE continues to partner with customers and local and state governments to advance a clean energy future and pursue emission reductions using a diverse portfolio of clean and renewable energy resources. The Company seeks to promote economy-wide emission reductions through electrification and smart energy use to help meet its GHG emission reduction goals.
Clean Electricity and GHG Legislation and Administrative Actions—In June 2021, the Oregon legislature passed House Bill 2021 (HB 2021), establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the state. A number of provisions in the bill align with PGE’s strategic direction. The GHG reduction targets applicable to these regulated entities are an 80% reduction in GHG
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emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. The bill was signed by the Governor on July 19, 2021. The baseline period for the investor-owned utilities is the average annual GHG emissions for the years 2010, 2011, and 2012 associated with the electricity sold to retail electricity consumers as reported to Oregon Department of Environmental Quality (ODEQ).
Utilities must develop a clean energy plan (CEP) for meeting the targets concurrent with the development of each Integrated Resource Plan (IRP). In reviewing the CEP, the OPUC must ensure that utilities demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions at reasonable costs to retail electricity consumers. The OPUC is also given authority to apply a performance incentive for early compliance with one or more of the clean energy targets.
Regulated entities will continue to report annual GHG emissions to ODEQ, as they do today. In compliance years, which are 2030, 2035, and 2040 and every year thereafter, the OPUC will use the data reported to ODEQ for that compliance year to determine whether the reduction targets are met. In determining compliance, if the utility has emissions in excess of the target, the OPUC must take into consideration emissions attributable to meeting load if the utility experienced unexpected challenges, such as transmission constraints or under-production from hydro and other renewable resources. The bill also includes certain compliance exceptions to protect customers, such as cost caps and mandatory reliability standards.
The legislation also:
•aligns with PGE decarbonization goals while protecting affordability and reliability;
•establishes clear decarbonization authority for the OPUC, including authority over electricity service suppliers (ESS);
•modernizes competition provisions of Oregon’s electricity restructuring law from 1999, Oregon Senate Bill 1149 (SB 1149),
•provides clear authority and process for a community-wide green tariff program for customers 30 kw and smaller with the ability to earn on program resources, and
•codifies non-bypassability of costs to ensure all customers pay their share of HB 2021 policy costs.
In March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions. As the Governor is limited by current statutory authority, the executive order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in prior legislative sessions.
Among other things, the executive order:
•Directed 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.
•Directed 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 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.
•Directed the ODEQ 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; and
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•More than doubled the reduction goals of the state’s Clean Fuels Program and extended the program, from the previous rule that required 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.
In 2016, Oregon Senate Bill 1547 (SB 1547) set a benchmark for how much electricity must come from renewable sources and required the elimination of coal from Oregon utility customers’ energy supply no later than 2030 (subject to an exception that allowed extension of this date until 2035 for PGE’s output from Colstrip).
Other 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 the Company’s Renewable Adjustment Clause (RAC) filings.
In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE’s investment in the Colstrip facility from 2042 to 2030. In January 2020, the owners of Colstrip Units 1 and 2 permanently retired those two 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 utilize certain common facilities with Units 1 and 2.
Although PGE is currently scheduled to recover the costs of Colstrip generation by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in their respective jurisdictions. In its most recent depreciation study filed with the OPUC in January 2021, PGE proposed to accelerate depreciation on Colstrip generation assets through 2027. In late July 2021, certain parties to PGE’s depreciation study docket (OPUC Docket UM 2152) reached a stipulated settlement, which will accelerate depreciation on the Colstrip generation assets through December 31, 2025. If the settlement is approved by the OPUC, the resulting depreciation rates would be utilized in the Company’s pending 2022 General Rate Case (2022 GRC). For further information on the 2022 GRC, see “General Rate Case” in the “Perform as a Business” section of this Overview. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of PGE’s exit from these facilities. See Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for information regarding legal proceedings related to Colstrip.
Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in the Pacific Northwest and neighboring states. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development might benefit from any excess transmission capacity that may become available.
As previously planned, in October 2020, PGE ceased coal-fired operation at its Boardman generating plant and has begun decommissioning activities.
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 and clean sources of energy. PGE’s 2016 IRP process resulted in the development of the following renewable resources:
•Wheatridge Renewable Energy Facility—In 2018, the Company issued a request for proposals seeking to procure approximately 100 average megawatts (MWa) of qualifying renewable resources. The prevailing
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bid was Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage. Construction on the solar and battery components is ongoing and expected to be placed in-service by the end of 2021. PGE owns 100 MW of the wind resource, which was placed in-service in the fourth quarter of 2020. Subsidiaries of NextEra Energy Resources, LLC own the balance of the wind resource, along with the solar and battery components, and will sell their portion of the output to PGE.
In May 2020, the OPUC issued an order that acknowledged the Company’s 2019 IRP and the Action Plan for PGE to undertake over the next four years to acquire the resources identified. The order also required 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 dispatchable capacity resources, such as energy storage. As a result, the following resources were procured:
•Douglas County Public Utility District (PUD)—PGE entered into an agreement with Douglas County PUD during 2020 to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. With a start date of January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MW toward a capacity need that PGE identified in its 2019 IRP; and
•Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS)—PGE has a 66.67% ownership interest in the 455 MW Pelton/Round Butte hydroelectric project on the Deschutes River, with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). The CTWS has an option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte in 2021. On June 30, 2021, the CTWS notified PGE of their intent to exercise this purchase option. Also on June 30, 2021, PGE executed a 16-year PPA with the CTWS that would commence in 2025 to purchase 100% of their current, and potential future, share of the project’s output. All conditions precedent to the effectiveness of the PPA were satisfied on October 19, 2021, and the Company expects CTWS to close on the purchase of their increased ownership interest, by the end of 2021. The Company filed with the OPUC a request for a waiver of the OPUC’s competitive bidding rules related to the PPA, which was adopted by the OPUC on October 5, 2021.
To meet the remaining capacity need identified in the 2019 IRP, the Company is seeking to procure both renewable and non-emitting, dispatchable resources in an All-Source RFP. PGE estimates that it will need to nearly triple the amount of clean and renewable energy serving customers to meet the Company’s 2030 emissions reduction target, in addition to removing coal from its portfolio. As a result, PGE estimates by 2030 it will need approximately 1,500 to 2,000 MW of clean and renewable resources and approximately 800 MW of non-emitting dispatchable capacity resources. PGE is working to exit from the coal-fired Colstrip plant by the end of 2025. On October 15, 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable and non-emitting resources. PGE will work with the OPUC to evaluate the opportunity to procure additional resources through this RFP, with a potential target of getting up to one-third of the clean resources needed to meet the 2030 emissions reduction target. The All-Source RFP seeks:
•Renewables—PGE expects to bring on approximately 375 to 500 MW of renewable resources;
•Non-emitting capacity—PGE will also be seeking approximately 375 MW on non-emitting dispatchable capacity resources that can be used on the hottest or the coldest days of the year; and
•Green Future Impact (GFI) Program—PGE expects to procure a resource or resources for the Company’s GFI Program through the 2021 All-Source RFP. Under the GFI Program, PGE can procure up to 100 MW of a new wind, solar, or hybrid renewable and battery storage resource to meet subscriber demand under the PGE supply option. The Company does not expect GFI Program resources considered in the 2021 All-Source RFP to contribute towards the cost-of-service 150 MWa energy cap envisioned under the 2019 IRP Action Plan, although that is subject to OPUC discretion.
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Renewable resources in PGE’s 2021 All-Source RFP must be RPS eligible, qualify for the federal PTC or the federal Investment Tax Credit and pass the cost-containment screen. All resources (dispatchable or renewable) must be online by the end of 2024, with certain exceptions for long-lead time pumped hydro resources. PGE has proposed a timeline to the OPUC that would have the Company issue the 2021 All-Source RFP in November 2021 with acknowledgement of a final shortlist during the second quarter of 2022. On October 6, 2021, the OPUC issued Order 21-320, which conditionally approved PGE’s scoring methodology for the 2021 All-Source RFP. Among the conditions, the OPUC will require PGE to consider bid submissions that would propose to repower existing generation resources.
On October 15 2021, PGE filed an extension waiver for the next IRP, which, if approved, would now be filed for consideration by the OPUC by March 2023.
PGE filed its inaugural Distribution System Plan (DSP) on October 15, 2021 which lays out plans to build a grid that supports a two-way energy ecosystem and empowers customers to make energy management choices to support decarbonization.
The Climate Pledge—On April 21, 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report GHG emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets.
Customer Choice Programs—PGE’s customers are committed to purchasing clean energy, as over 230,000 residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area continue to consider similar goals.
In response, the Company implemented a new customer service option, the GFI Program, which allows for 100 MW of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the OPUC in the first quarter of 2019, the program provides business customers access to bundled renewable attributes from those resources. On March 29, 2021, the OPUC issued an order that expanded the program by 200 MW and provided for the possibility of PGE ownership of the underlying renewable resources under certain conditions. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, and reliable integrated power while providing customer choice and a cleaner energy system.
Renewable Recovery Framework—As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the Renewable Adjustment Clause (RAC). The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 General Rate Case (2019 GRC) Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. There have been no significant filings made under the RAC during 2021.
Electrify other sectors of the economy—PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include:
•The use of electricity in more applications such as electric vehicles and heat pumps;
•The integration of new, geographically-diverse energy markets;
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•The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation;
•The development of connected neighborhood microgrids and smart communities; and
•The use of data and analytics to better predict demand and support energy-saving customer programs.
In July 2019, PGE’s Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support functions. As of September 30, 2021, the Company has recorded $167 million, including AFDC, in construction work-in-progress related to the IOC. The project is expected to be placed in-service in the fourth quarter of 2021.
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. In June 2019, the Oregon Legislature enacted Oregon Senate Bill 1044 (SB 1044), which establishes Oregon’s zero emissions vehicle goals in statute at 250 thousand zero emission vehicle sales by 2025 and 90% of all new vehicle sales to be zero emission 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’s carbon reduction goals. In October 2020, the OPUC approved the plan and related costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. In 2021, the Oregon legislature enacted House Bill 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification.
Perform as a business—PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on such matters.
General Rate Case—On July 9, 2021, PGE filed with the OPUC a general rate case based on a 2022 test year (GRC). The filing requests an increase in PGE's annual revenue requirement that, when combined with changes in supplemental schedules, results in an overall average increase of approximately 3.9% in customer prices for 2022. The net price increase and annual revenue requirement includes a 2.0% average price increase as a result of higher net variable power costs expected in 2022, as reflected in the Annual Power Cost Update Tariff (AUT) filed with the OPUC in April 2021. The GRC filing seeks recovery of base business investments in upgrading the grid to improve reliability, resiliency, and capability to deliver safe, reliable, clean electricity to customers.
PGE has invested heavily in its transmission and distribution system to meet the needs of customers by addressing new and growing load and strengthening the grid for new challenges with extreme weather and wildfires. These investments include needed pole and underground wire replacements, substation upgrades, and other additions.
The cornerstone of the transmission and distribution investments is a new IOC, set to open in the fourth quarter of 2021. Acting as the nerve center of PGE's system, the IOC will enable the Company to apply smart technologies to keep an increasingly complex set of clean energy resources operating efficiently. The system integrations at the IOC will strengthen physical and cyber security of the system to meet critical infrastructure standards, such as seismic and other natural disaster readiness, with the aim of achieving greater reliability with fewer and shorter outages.
The Company also will deploy a new software platform called the Advanced Distribution Management System that is designed to allow the Company to reduce outages by proactively detecting and responding to issues before they impact customers and providing self-healing technology for restoring power.
The GRC also reflects significant investments geared toward protecting the lives and property of Oregonians. As Oregon’s weather gets hotter and drier, increasing the risk of catastrophic wildfires, the Company is intensifying
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efforts to keep the system safe from wildfire-related events and resilient from weather and disaster-related crises. Key to these efforts are expansion of the vegetation management program and system hardening to help mitigate potential outages arising from wildfire and severe weather year-round.
The proposed net increase in annual revenue requirement in the GRC is based upon:
•A capital structure of 50% debt and 50% equity;
•A return on equity of 9.5%;
•A cost of capital of 6.94%; and
•A rate base of $5.7 billion.
PGE, OPUC staff, and certain customer groups have reached an agreement that resolves cost of capital issues in the case. All other elements of the case remain unsettled.
The agreement allows for:
•A capital structure of 50% debt and 50% equity;
•A return on equity of 9.5%; and
•A cost of capital of 6.83%, which reflects updates for actual and forecasted debt costs.
This stipulation remains subject to OPUC approval. PGE will continue to work with Parties throughout this proceeding to resolve all other unsettled elements of the case.
Regulatory review of the 2022 GRC will continue throughout 2021 and into 2022, with a final OPUC order expected to be issued by April 2022. PGE has proposed that new customer prices become effective May 2022. Price changes for the AUT and the supplemental schedule items are expected to occur January 1, 2022.
The 2022 GRC filing (Docket UE 394) is available on the OPUC website at www.oregon.gov/puc.
COVID-19 Impacts—The COVID-19 pandemic has had a variety of adverse impacts on economic activity. The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. As a result of these activities and economic hardships, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs.
On March 20, 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities which may qualify for deferral under Docket UM2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent to the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020.
For the three months ended September 30, 2021, PGE recorded an $11 million increase to its COVID-19 deferral. As of September 30, 2021 and December 31, 2020, PGE’s deferred balance was $27 million and $10 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE expects incremental bad debt expense to be $34 million to $36 million for the year ending 2021, which includes the expected effect of billing assistance to be provided to customers during the remainder of
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the year. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings review.
PGE believes the full amount of the 2020 and 2021 deferrals is probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
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 to utilities that issued short-term debt in response to the COVID-19 emergency and the detrimental impacts the issuance of short-term debt has on the allowance for equity funds used during construction. PGE adopted the waiver in the second quarter of 2020 and retrospectively applied its provisions as of March 2020. On February 23, 2021, FERC issued an order extending the waiver an additional seven months, to be effective March 1, 2021 through September 30, 2021. On September 21, 2021, FERC issued an additional order to further extend the waiver through March 31, 2022. PGE has adopted all waiver extensions.
Wildfire—In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE’s wildfire mitigation planning includes regular system-wide risk assessment, which led to the identification and activation of a PSPS in a zone near Mt. Hood that was identified as a region at high risk of wildfire in 2020. Additionally, in response to wildfires across Oregon in 2020, PGE cut power to eight additional high-risk fire areas in partnership with local and regional agencies. The Company is intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises. These efforts include enhanced tree and brush clearing, replacing equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment.
PGE continues to incur costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs. As of September 30, 2021 and December 31, 2020, PGE’s cumulative deferred costs related to the wildfire response was $36 million and $15 million, respectively. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. PGE believes the full amount of the 2020 and 2021 deferrals is probable of recovery as the Company’s prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
February 2021 Ice Storms and Damage—Beginning on February 11, 2021, an historic set of storms involving heavy snow, winds and ice impacted the United States, including PGE’s service territory. On February 13, 2021, Oregon’s Governor declared a state of emergency due to severe winter weather that resulted in heavy snow and ice accumulation, high winds, critical transportation failures, and loss of power and communications capabilities. The wind and ice from the storms caused significant damage to PGE’s transmission and distribution systems, which resulted in over 750,000 outages, with many customers affected more than once. At peak activity during the recovery, PGE deployed over 400 repair crews across the service territory, with many of these crews provided through mutual aid arrangements from throughout the West.
Through September 30, 2021, PGE has incurred an estimated $107 million in incremental costs due to the storms, of which $36 million were capital and recorded to Electric utility plant, net and $71 million were operating expenses
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associated with transmission and distribution. Beginning in 2019, the OPUC authorized the Company to collect $4 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In response to the February storms, PGE exhausted its storm collection balance for 2021 of $9 million, which was used to offset operating expenses. After accounting for storm deferral tracking mechanisms already in place, the cumulative incurred operating expenses from the February storm damage are estimated to be $62 million as of September 30, 2021.
On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) and as of September 30, 2021, the Company has deferred a total of $60 million, including interest, related to incremental operating expenses due to the storms. PGE expects to incur and defer additional costs subsequent to the storms related to replacing and rebuilding PGE facilities damaged by the storms, as well as addressing vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. PGE does not expect an OPUC decision on the February storms deferral until sometime during 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery and their conclusions of overall prudence, including an earnings review, and could result in a portion, or all, of PGE’s deferral being disallowed for recovery.
Declared states of emergency—On September 22, 2021, the OPUC issued an order that approved a pre-authorized deferral of costs associated with declared states of emergency. Qualifying events consist of federal or state declared emergencies with impacts on PGE’s service territory. Previously the Company had to file a request for deferred accounting when an event of that nature occurred, such as the Labor Day 2020 wildfire event, and had to seek OPUC approval of such deferred accounting applications to be effective. With this order, PGE would provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to use deferred accounting to track incremental costs related to the emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices including a review of utility prudence in a future proceeding, among other requirements.
Power Costs—Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2021 AUT included a final increase in power costs for 2021, and a corresponding increase in annual revenue requirement, of $66 million from 2020 levels, which were reflected in customer prices effective January 1, 2021. See “Power Operations” within this Overview section of Item 2 for more information regarding the PCAM.
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 Superfund site. As of September 30, 2021, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company’s recovery mechanism allows the Company to defer and recover estimated liabilities and incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including but not limited to insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE’s results of operations may be impacted to the extent such expenditures are deemed
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imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”
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 an estimated net refund of $9 million to customers for the nine months ended September 30, 2021, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. In the third quarter of 2021, the Company continued to see 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 2% 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 2021, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2023. The Company reached its 2021 limit for collection from commercial customers during the third quarter of 2021. No limit exists for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which have largely offset the revenue increases that have resulted from higher residential demand.
As of December 31, 2020, PGE had recorded an estimated net refund of $6 million for 2020, which if approved by the OPUC, will be credited to customers over a one-year period beginning January 1, 2022.
Deferral of Boardman Revenue Requirement—In October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with Boardman currently included in customer prices as established in the Company’s 2019 GRC. The application states a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. On October 7, 2021, intervenors filed a motion with the OPUC requesting to consolidate the open Boardman deferral docket with PGE’s open 2022 GRC docket. Combining the dockets would provide an avenue under which the OPUC could make a separate decision on the issues associated with the Boardman deferral within PGE’s 2022 GRC docket. PGE has objected to the request by intervenors on the basis that the two dockets are not similar enough to warrant consolidation and would have the effect of expanding the scope and complicating the GRC proceeding. However, if the OPUC were to approve the consolidation of proceedings, PGE would work with the OPUC and parties to establish an appropriate schedule and process to allow for a fair determination for both matters.
PGE estimates this amount could be up to $14 million for the period ended December 31, 2020 and $66 million for the year ending December 31, 2021. As of September 30, 2021 and December 31, 2020, PGE has not recorded a regulatory liability pursuant to this deferral application as the Company believes its current prices are just and reasonable in light of PGE’s continued substantial investments in utility plant. The costs of these investments, which are not currently reflected in customer prices, more than offset the revenue requirement for Boardman. If the OPUC authorizes a refund, PGE would record a regulatory liability with a corresponding charge to earnings.
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 Western Energy Imbalance Market, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable
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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 instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.
Customers and Demand—The following tables present total energy deliveries and the average number of retail customers by customer type for the periods indicated.

| Three Months Ended September 30, | % Increase (Decrease) in Energy Deliveries |  |  | Nine Months Ended September 30, | % Increase (Decrease) in Energy Deliveries |
| 2021 |  |  | 2020 |  |  | 2021 |  | 2020 |
Energy deliveries (MWhs in thousands): |  |  |  |  |  |  |  |  |  |  |
Retail: |  |  |  |  |  |  |  |  |  |  |  |  |
Residential | 1,872 |  |  |  | 1,832 |  | 2 | % |  |  | 5,875 |  |  |  | 5,621 |  | 5 | % |
Commercial | 1,778 |  |  |  | 1,672 |  | 6 | % |  |  | 4,943 |  |  |  | 4,672 |  | 6 | % |
Industrial | 960 |  |  |  | 914 |  | 5 | % |  |  | 2,773 |  |  |  | 2,552 |  | 9 | % |
Subtotal | 4,610 |  |  |  | 4,418 |  | 4 | % |  |  | 13,591 |  |  |  | 12,845 |  | 6 | % |
Direct access: |  |  |  |  |  |  |  |  |  |  |  |  |
Commercial | 155 |  |  |  | 167 |  | (7) | % |  |  | 453 |  |  |  | 478 |  | (5) | % |
Industrial | 467 |  |  |  | 389 |  | 20 | % |  |  | 1,228 |  |  |  | 1,114 |  | 10 | % |
Subtotal | 622 |  |  |  | 556 |  | 12 | % |  |  | 1,681 |  |  |  | 1,592 |  | 6 | % |
Total retail energy deliveries | 5,232 |  |  |  | 4,974 |  | 5 | % |  |  | 15,272 |  |  |  | 14,437 |  | 6 | % |
Wholesale energy deliveries | 1,912 |  |  |  | 1,613 |  | 19 | % |  |  | 4,416 |  |  |  | 4,593 |  | (4) | % |
Total energy deliveries | 7,144 |  |  |  | 6,587 |  | 8 | % |  |  | 19,688 |  |  |  | 19,030 |  | 3 | % |

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Average number of retail customers: |  |  |  |  |  |  |  |  |
Residential | 801,147 | 88 | % |  | 792,155 | 88 | % |  | 799,182 |  | 88 | % |  | 789,726 | 88 | %
Commercial | 111,063 | 12 |  |  | 110,323 | 12 |  |  | 110,863 |  | 12 |  |  | 110,185 | 12 |
Industrial | 190 | — |  |  | 194 | — |  |  | 191 |  | — |  |  | 194 | — |
Direct access | 582 | — |  |  | 641 | — |  |  | 589 |  | — |  |  | 634 | — |
Total | 912,982 |  | 100 | % |  | 903,313 |  | 100 | % |  | 910,825 |  | 100 | % |  | 900,739 |  | 100 | %

Retail energy deliveries for the nine months ended September 30, 2021 increased 6% compared with the nine months ended September 30, 2020, as reflected by increases in all customer classes. In the third quarter 2021, Total retail energy deliveries increased 5%, reflecting continued strength in the industrial class, improvement in the commercial class, which suffered the largest contraction during 2020 due to the COVID-19 pandemic, and growth in the residential class, partially driven by customer response to the unusually hot summer temperatures.
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Residential loads increased with the onset of the pandemic in early 2020, as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in an attempt to maintain social distancing or closed as a result of the lack of business as residents followed directives from state and federal authorities. The industrial class as a whole experienced an increase in energy deliveries, due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from noted closures than other sectors. As the economy has reopened during 2021, PGE has experienced greater commercial customer demand. Residential usage continues to be elevated as remote and hybrid work schedules remain in place across the Company’s service area.
The following table indicates the number of heating and cooling degree-days for the three and nine months ended September 30, 2021 and 2020, along with the current 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
| 2021 |  | 2020 |  | Avg. |  | 2021 |  | 2020 |  | Avg.
First Quarter | 1,805 |  |  | 1,761 |  |  | 1,847 |  |  | — |  |  | — |  |  | — |
Second Quarter | 498 |  |  | 554 |  |  | 629 |  |  | 238 |  |  | 99 |  |  | 93 |
July | — |  |  | 11 |  |  | 7 |  |  | 258 |  |  | 180 |  |  | 182 |
August | 9 |  |  | 1 |  |  | 6 |  |  | 249 |  |  | 197 |  |  | 196 |
September | 45 |  |  | 35 |  |  | 61 |  |  | 93 |  |  | 115 |  |  | 77 |
Third Quarter | 54 |  |  | 47 |  |  | 74 |  |  | 600 |  |  | 492 |  |  | 455 |
Year-to-date | 2,357 |  |  | 2,362 |  |  | 2,550 |  |  | 838 |  |  | 591 |  |  | 548 |
Increase/(Decrease) from the 15-year average | (8) | % |  | (7) | % |  |  |  | 53 | % |  | 8 | % |  |

The impact of the higher temperatures during the summer months contributed to an increase in retail energy deliveries and resulting retail revenues. In late June 2021, PGE’s service territory experienced record breaking heat, with temperatures in Portland, Oregon exceeding all-time highs for three consecutive days. On the third day of the event, June 28, 2021, when the Portland temperature reached 116 degrees, the Company recorded a new system peak load of 4,441 MW, which surpassed the previous all-time mark of 4,073 MW and the previous summer system peak load of 3,976 MW. A second heat event occurred in early August that drove demand to 4,352 MW, also considerably exceeding the previous peak loads.
After adjusting for the effects of weather, retail energy deliveries for the nine months ended September 30, 2021 increased 4.0% compared to the same period of 2020. The increase reflects increases of 9% in industrial deliveries, 4% in commercial energy deliveries, and 1% in residential energy deliveries. Residential average usage per customer has held steady during 2021, while growth of 1.2% in the average number of residential customers contributed to increased energy deliveries in total.
The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from Electricity Service Suppliers (ESSs). This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE’s total retail energy deliveries for the first nine months of 2021.
In early February 2020, PGE began offering service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 18% of the Company’s energy deliveries could have been supplied by ESSs. Actual energy deliveries to Direct Access customers by ESSs represented 11% of PGE’s total retail energy deliveries for the first nine months of 2021 and 2020.
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Energy efficiency and conservation efforts by retail customers influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See “Decoupling” in this Overview section of Item 7, for further information on the decoupling mechanism.
Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. 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 and impacts NVPC and income from operations.
The following table provides information regarding the performance of the Company’s generating resources for the nine months ended September 30, 2021 and 2020:

| Plant availability (1) |  | Actual energy provided compared to projected levels (2) |  | Actual energy provided as a percentage of total retail load |  |  |  |  |
| 2021 | 2020 |  |  | 2021 | 2020 |  | 2021 | 2020 |  |  |  |  |
Generation: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Thermal: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | 90 | % | 93 | % |  |  | 126 | % | 73 | % |  | 49 | % | 42 | % |  |  |  |  |
Coal (3) | — |  | 99 |  |  |  | 102 |  | 93 |  |  | 10 |  | 20 |  |  |  |  |  |
Wind | 84 |  | 95 |  |  |  | 110 |  | 113 |  |  | 13 |  | 13 |  |  |  |  |  |
Hydro | 93 |  | 88 |  |  |  | 74 |  | 76 |  |  | 5 |  | 7 |  |  |  |  |  |

(1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages.
(2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.
(3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 92% during the nine months ended September 30, 2021, compared with 79% in 2020. Boardman ceased coal-fired generation on October 15, 2020.
Energy received from PGE-owned and jointly-owned thermal plants during the nine months ended September 30, 2021 compared to 2020 remained materially consistent. In 2021 production at the Company’s natural gas-fired plants increased to meet retail load demands, partially offset by a decrease in coal production. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable c osts 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.
Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 55% during the nine months ended September 30, 2021 compared to 2020. Energy received from mid-Columbia and other regional hydroelectric projects increased 95% in the nine months ended September 30, 2021 due to new PPAs in place in 2021 as compared to 2020. The energy generated by the Company-owned facilities decreased 15%, due to less favorable hydro conditions in 2021. 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. See “Purchased power and fuel” in the Results of Operations section in this Item 2, for further detail on regional hydro results.
Energy received from PGE-owned wind resources and under contracts increased 31% during the nine months ended September 30, 2021 compared to 2020 primarily due to the addition of Wheatridge, and favorable wind conditions.
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Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation increase in comparison to projected levels, more PTCs were produced in 2021 than what was contemplated in the Company’s prices.
For Wheatridge, wind generation studies were used to develop NVPC cost forecasts, which were included in the RAC filing for the facility, and included in customer prices when the facility went into service. The RAC tariff included NVPC in 2020 along with all other aspects of the revenue requirement. Beginning January 1, 2021, the NVPCs were included in the Company’s AUT, although the other aspects of the RAC tariff will remain in effect until they are included in customer prices as a result of a future general rate case.
Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for the nine months ended September 30, 2021 and 2020, respectively:
•For the nine months ended September 30, 2021, actual NVPC was $60 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be above the baseline, and outside the established deadband range. Pursuant to the PCAM and related earnings test, as of September 30, 2021, PGE has deferred $27 million which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, and could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
•For the nine months ended September 30, 2020, actual NVPC was $27 million below baseline NVPC. For the year ended December 31, 2020, actual NVPC, excluding certain trading losses totaling $127 million, was $13 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded pursuant to the PCAM for 2020. The 2020 PCAM was filed with the OPUC in June 2021 with a final order anticipated in December 2021.
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, 2020, filed with the SEC on February 19, 2021.
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.
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The results of operations are as follows for the periods presented (dollars in millions):

| Three Months Ended September 30, | % Increase (Decrease) |  |  |  | Nine Months Ended September 30, | % Increase (Decrease) |  |
| 2021 |  |  |  | 2020 |  |  |  | 2021 |  | 2020 |  |
Total revenues | $ | 642 |  |  |  |  | $ | 547 |  | 17 | % |  |  |  | $ | 1,788 |  |  |  |  | $ | 1,589 |  | 13 | % |  |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchased power and fuel | 259 |  |  |  |  | 292 |  | (11) | % |  |  |  | 613 |  |  |  |  | 554 |  | 11 | % |  |
Generation, transmission and distribution | 80 |  |  |  |  | 65 |  | 23 | % |  |  |  | 236 |  |  |  |  | 215 |  | 10 | % |  |
Administrative and other | 82 |  |  |  |  | 63 |  | 30 | % |  |  |  | 247 |  |  |  |  | 208 |  | 19 | % |  |
Depreciation and amortization | 101 |  |  |  |  | 108 |  | (6) | % |  |  |  | 305 |  |  |  |  | 320 |  | (5) | % |  |
Taxes other than income taxes | 37 |  |  |  |  | 35 |  | 6 | % |  |  |  | 110 |  |  |  |  | 104 |  | 6 | % |  |
Total operating expenses | 559 |  |  |  |  | 563 |  | (1) | % |  |  |  | 1,511 |  |  |  |  | 1,401 |  | 8 | % |  |
Income from operations | 83 |  |  |  |  | (16) |  | (619) | % |  |  |  | 277 |  |  |  |  | 188 |  | 47 | % |  |
Interest expense, net(1) | 33 |  |  |  |  | 35 |  | (6) | % |  |  |  | 100 |  |  |  |  | 102 |  | (2) | % |  |
Other income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Allowance for equity funds used during construction | 4 |  |  |  |  | 4 |  | — | % |  |  |  | 13 |  |  |  |  | 11 |  | 18 | % |  |
Miscellaneous income, net | 1 |  |  |  |  | 3 |  | (67) | % |  |  |  | 6 |  |  |  |  | 2 |  | 200 | % |  |
Other income, net | 5 |  |  |  |  | 7 |  | (29) | % |  |  |  | 19 |  |  |  |  | 13 |  | 46 | % |  |
Income before income tax expense | 55 |  |  |  |  | (44) |  | (225) | % |  |  |  | 196 |  |  |  |  | 99 |  | 98 | % |  |
Income tax expense | 5 |  |  |  |  | (27) |  | (119) | % |  |  |  | 18 |  |  |  |  | (4) |  | (550) | % |  |
Net income | $ | 50 |  |  |  |  | $ | (17) |  | (394) | % |  |  |  | $ | 178 |  |  |  |  | $ | 103 |  | 73 | % |  |

(1) Includes an allowance for borrowed funds used during construction of $3 million and $2 million for the three months ended September 30, 2021 and 2020, and $7 million and $6 million for the nine months ended September 30, 2021 and 2020, respectively.
Net income for the three months ended September 30, 2021 increased $67 million from the comparable period of 2020, which contained $127 million of Purchased power and fuel costs due to the previously reported energy trading losses. In 2021, Purchased power and fuel expenses were impacted due in part to lower hydro and wind production in the region, which more than offset increases in revenues resulting from higher retail energy deliveries with the economy reopening along with increased customer demand due to unusually warm temperatures. Retail revenues were also impacted by a slightly lower average price mix in 2021 due to the return of commercial demand from the contraction in that sector that occurred in 2020. Wholesale revenues increased primarily due to higher market prices. Operating expenses increased, driven by preparations in advance of wildfire season, tree trimming, wage pressure, and higher legal and benefits expenses.
Net income for the nine months ended September 30, 2021 increased $75 million from the first nine months of 2020. While customer growth continues, increases in revenues from retail energy deliveries and wholesale sales were largely offset by higher Purchased power and fuel expenses after removing the impact of the previously reported energy trading losses from the 2020 results. The Company benefited from the sale of excess natural gas back into the wholesale market, the addition of Wheatridge to the generation portfolio, increased AFDC equity, and interest income on Regulatory Assets, all of which were offset by higher Administrative and general expenses.
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Total revenues consist of the following for the periods presented (dollars in millions):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Retail (1): |  |  |  |  |  |  |  |  |  |  |
Residential | $ | 265 |  | 41 | % |  | $ | 245 |  | 45 | % |  | $ | 824 |  | 46 | % |  | $ | 747 |  | 47 | %
Commercial | 186 |  | 29 |  |  | 164 |  | 30 |  |  | 518 |  | 29 |  |  | 463 |  | 29 |
Industrial | 65 |  | 10 |  |  | 58 |  | 11 |  |  | 187 |  | 10 |  |  | 162 |  | 10 |
Direct Access | 11 |  | 2 |  |  | 12 |  | 2 |  |  | 35 |  | 2 |  |  | 35 |  | 2 |
Subtotal | 527 |  | 82 |  |  | 479 |  | 88 |  |  | 1,564 |  | 88 |  |  | 1,407 |  | 88 |
Alternative revenue programs, net of amortization | (12) |  | (2) |  |  | (9) |  | (2) |  |  | (23) |  | (1) |  |  | — |  | — |
Other accrued revenues, net (2) | 1 |  | — |  |  | 7 |  | 1 |  |  | 12 |  | 1 |  |  | 13 |  | 1 |
Total retail revenues | 516 |  | 80 |  |  | 477 |  | 87 |  |  | 1,553 |  | 88 |  |  | 1,420 |  | 89 |
Wholesale revenues | 112 |  | 17 |  |  | 56 |  | 10 |  |  | 186 |  | 10 |  |  | 130 |  | 8 |
Other operating revenues | 14 |  | 2 |  |  | 14 |  | 3 |  |  | 49 |  | 3 |  |  | 39 |  | 3 |
Total revenues | $ | 642 |  | 100 | % |  | $ | 547 |  | 100 | % |  | $ | 1,788 |  | 100 | % |  | $ | 1,589 |  | 100 | %

(1) Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those customers that purchase their energy from ESSs.
(2) Amounts for the nine months ended September 30, 2021, included $9 million that resulted from use of the storm cost deferral to partially offset expenses related to the January and February storms. Amount for the nine months ended September 30, 2020 included $17 million in amortization, including interest, related to the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA).
Total retail revenues—The following items contributed to the increase in Total retail revenues for the three and nine months ended September 30, 2021 compared to the same period in 2020 as follows (dollars in millions):

| Three Months Ended | Nine Months Ended |
September 30, 2020 | $ | 477 |  | $ | 1,420 |  |
Increase from higher retail energy deliveries driven by the impact of weather and customer load growth | 24 |  | 79 |  |
Increase as a result of the AUT, approved by the OPUC | 19 |  | 51 |  |
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertains to Wheatridge being placed into service | 7 |  | 27 |  |
Recovery in Revenues of Storm related expenses in 2021 | — |  | 12 |  |
Decrease as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19 | (8) |  | (13) |  |
Decrease attributed to alternative revenue programs related to the decoupling mechanism due to increased residential use per customer | (3) |  | (23) |  |
September 30, 2021 | $ | 516 |  | $ | 1,553 |  |
Change in Total retail revenues | $ | 39 |  | $ | 133 |  |

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Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company’s efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.
For the three months ended September 30, 2021 wholesale revenues increased $56 million, or 100%, from the three months ended September 30, 2020, as a result of a $45 million increase from a 68% increase in average wholesale sales prices, and by an $11 million increase related to 19% higher wholesale sales volume. The price increase was due to weaker than average regional hydro production in 2021, reduced regional capacity, and the demand impact resulting from the unusual heat events experienced in 2021.
Wholesale revenues for the nine months ended September 30, 2021 increased $56 million from the nine months ended September 30, 2020, as a $61 million increase from 49% higher average wholesale sales price was partially offset by a $5 million reduction due to a 4% decline in sales volumes. Poor hydro conditions, reduced regional thermal generation capacity and more extreme weather experienced during 2021, including the unprecedented heat event that occurred late in the second quarter of 2021 in combination with increased retail load requirements drove prices higher.
Other operating revenues for the three months ended September 30, 2021 were consistent with the three months ended September 30, 2020.
Other operating revenue for the nine months ended September 30, 2021 increased $10 million from the nine months ended September 30, 2020 driven primarily by market conditions that provided more 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 significantly higher in 2021 after being depressed in 2020 due to milder than average winter temperatures in North America in 2020 that resulted in an oversupply of natural gas and lower prices.
Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts.
The following items contributed to the change in Purchased power and fuel for the three and nine months ended September 30, 2021 compared to the same period in 2020 as follows (dollars in millions, except for average variable power cost per MWh):

| Three Months Ended | Nine Months Ended
September 30, 2020 | $ | 292 |  | $ | 554 |
Increase (Decrease) related to average variable power cost per MWh | (78) |  | 55 |
Increase related to total system load | 72 |  | 31 |
PCAM deferral | (27) |  | (27) |
September 30, 2021 | 259 |  | 613 |
Change in Purchased power and fuel | $ | (33) |  | $ | 59 |
Average variable power cost per MWh: |  |
September 30, 2020 | $ | 46.62 |  | $ | 30.44 |
September 30, 2021 | $ | 42.19 |  | $ | 34.09 |
Total system load (MWhs in thousands): |  |
September 30, 2020 | 6,251 | 18,201
September 30, 2021 | 6,781 | 18,772

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For the three months ended September 30, 2021, the $78 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 24% decrease in the average cost of purchased power, and a 10% increase on the average cost for the Company’s own generation. The decrease in average variable power cost per MWh is primarily attributed to the previously reported energy trading losses in 2020. The $72 million increase related to total system load was primarily due to a 33% increase in energy deliveries obtained from purchased power to meet retail load demand.
For the nine months ended September 30, 2021 the $55 million increase related to the change in average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 16% increase on the average cost of purchased power, offset by a 5% decrease on the average cost for the Company’s own generation. The $31 million increase related to total system load was primarily due to a 8% increase in energy deliveries obtained from purchased power.
For more information regarding PGE’s PCAM deferral, see Actual NVPC within this Results of Operations.
PGE’s sources of energy, total system load, and retail load requirement for the periods presented are as follows:

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2021 |  | 2020 |  | 2021 |  | 2020
Sources of energy (MWhs in thousands): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Generation: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Thermal: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas | 2,785 |  |  | 41 | % |  | 2,290 |  |  | 37 | % |  | 7,074 |  |  | 38 | % |  | 5,767 |  |  | 32 | %
Coal | 560 |  |  | 8 |  |  | 1,248 |  |  | 20 |  |  | 1,455 |  |  | 8 |  |  | 2,752 |  |  | 15 |
Total thermal | 3,345 |  |  | 49 |  |  | 3,538 |  |  | 57 |  |  | 8,529 |  |  | 46 |  |  | 8,519 |  |  | 47 |
Hydro | 197 |  |  | 3 |  |  | 233 |  |  | 4 |  |  | 778 |  |  | 4 |  |  | 919 |  |  | 5 |
Wind | 646 |  |  | 10 |  |  | 527 |  |  | 8 |  |  | 1,843 |  |  | 10 |  |  | 1,720 |  |  | 9 |
Total generation | 4,188 |  |  | 62 |  |  | 4,298 |  |  | 69 |  |  | 11,150 |  |  | 60 |  |  | 11,158 |  |  | 61 |
Purchased power: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Term * | 1,429 |  |  | 21 |  |  | 1,382 |  |  | 22 |  |  | 3,782 |  |  | 20 |  |  | 5,202 |  |  | 29 |
Hydro * | 906 |  |  | 13 |  |  | 493 |  |  | 8 |  |  | 3,091 |  |  | 16 |  |  | 1,585 |  |  | 9 |
Wind | 258 |  |  | 4 |  |  | 78 |  |  | 1 |  |  | 749 |  |  | 4 |  |  | 256 |  |  | 1 |
Total purchased power | 2,593 |  |  | 38 |  |  | 1,953 |  |  | 31 |  |  | 7,622 |  |  | 40 |  |  | 7,043 |  |  | 39 |
Total system load | 6,781 |  |  | 100 | % |  | 6,251 |  |  | 100 | % |  | 18,772 |  |  | 100 | % |  | 18,201 |  |  | 100 | %
Less: wholesale sales | (1,912) |  |  |  |  | (1,613) |  |  |  |  | (4,416) |  |  |  |  | (4,593) |  |  |
Retail load requirement | 4,869 |  |  |  |  | 4,638 |  |  |  |  | 14,356 |  |  |  |  | 13,608 |  |  |

* PGE has reclassified sources of energy previously reported as purchased from Term resources to Hydro resources in the amounts of 155 MWhs for the three months ended March 31, 2020, 133 MWhs for the three months ended June 30, 2020, 95 MWhs for the three months ended September 30, 2020, and 809 MWhs for the three months ended March 31, 2021.
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The following table presents the actual April-to-September 2021 and the actual 2020 runoff at particular points of major rivers relevant to PGE’s hydro resources:

| Runoff as a Percent of Normal*
Location | 2021 Actual |  | 2020 Actual
Columbia River at The Dalles, Oregon | 82 | % |  | 104 | %
Mid-Columbia River at Grand Coulee, Washington | 89 |  |  | 109 |
Clackamas River at Estacada, Oregon | 70 |  |  | 75 |
Deschutes River at Moody, Oregon | 84 |  |  | 86 |

* 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 in Actual NVPC for the three and nine months ended September 30, 2021 compared to the same period in 2020 as follows (dollars in millions):

| Three Months Ended | Nine Months Ended
September 30, 2020 | $ | 236 |  | $ | 424 |
Increase (Decrease) in Purchased power and fuel expense | (6) |  | 86 |
Increase in Wholesale revenues | (56) |  | (56) |
Decrease due to PCAM deferral | (27) |  | (27) |
September 30, 2021 | $ | 147 |  | $ | 427 |
Change in NVPC | $ | (89) |  | $ | 3 |

For further information regarding NVPC in relation to the PCAM, see “Purchased power and fuel expense” and “Revenues” within this “Results of Operations” for more details.
For the three months ended September 30, 2021 and 2020, actual NVPC was $53 million above and $11 million above baseline NVPC, respectively. For the nine months ended September 30, 2021 and 2020, actual NVPC was $60 million above and $27 million below baseline NVPC, respectively.
Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be above the baseline, and outside the deadband. Pursuant to the PCAM and related earnings test, as of September 30, 2021, PGE has deferred $27 million which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, and could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
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Generation, transmission and distribution - The following items contributed to the increase in Generation, transmission and distribution for the three and nine months ended September 30, 2021 compared to the same period in 2020 (dollars in millions):

| Three Months Ended | Nine Months Ended
September 30, 2020 | $ | 65 |  | $ | 215 |
January and February storm costs recovered via the Company’s storm cost recovery mechanism | — |  | 12 |
Higher distribution expenses for wildfire risk mitigation and storm restoration | 5 |  | 10 |
Higher vegetation management expenses | 5 |  | 7 |
Net decrease in maintenance expense at the Company’s generation facilities | (3) |  | (7) |
Miscellaneous expenses | 8 |  | (1) |
September 30, 2021 | $ | 80 |  | $ | 236 |
Change in Generation, transmission and distribution | $ | 15 |  | $ | 21 |

PGE deferred $6 million and $56 million of incremental costs for the three and nine months ended September 30 2021, respectively, related to February 2021 ice storm damage in PGE’s service territory. See “February 2021 Ice Storm” within “Perform as a Business” under the “Overview” section of this Item 2. for more information.
Administrative and other - The following items contributed to the increase in Administrative and other for the three and nine months ended September 30, 2021 compared to the same period in 2020 as follows (dollars in millions):

| Three Months Ended | Nine Months Ended
September 30, 2020 | $ | 63 |  | $ | 208 |
Higher employee compensation and benefits expenses | 6 |  | 14 |
Higher legal and other professional service expenses | 6 |  | 13 |
Increase (decrease) in bad debt expense | 2 |  | (1) |
Miscellaneous expenses | 5 |  | 13 |
September 30, 2021 | $ | 82 |  | $ | 247 |
Change in Administrative and other | $ | 19 |  | $ | 39 |

Depreciation and amortization expense decreased $7 million and $15 million in the three and nine months ended September 30, 2021 compared to the same period in 2020, largely as a result of asset retirements, which were partially offset by capital additions, and regulatory amortization.
Taxes other than income taxes expense increased $2 million and $6 million in the three and nine months ended September 30, 2021 compared with 2020. The variance for the three months ended September 30, 2021 was primarily attributable to higher franchise taxes. The variance for the nine months ended September 30, 2021 was primarily attributable to higher Oregon property taxes as well as higher franchise taxes.
Interest expense, net decreased $2 million in both the three and nine months ended September 30, 2021 compared to the same period in 2020.
Other income, net decreased $2 million for the three months ended September 30, 2021 compared to the same period in 2020 driven by market changes on the non-qualified benefit trust. Other income, net increased $6 million for the nine months ended September 30, 2021 compared to the same period in 2020. The increase was primarily
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due to higher AFDC equity income on higher construction work-in-progress balances and higher interest income on regulatory deferral balances.
Income tax expense increased $32 million and $22 million for three and nine months ended September 30, 2021, compared to the same period in 2020. The increase for the three months ended September 30, 2021 was driven by higher pre-tax income, partially offset by regulatory amortizations. The increase for the nine months ended September 30, 2021 was driven by higher pre-tax income. The increase was partially offset by a cumulative catch-up adjustment recorded in the first quarter of 2021 to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax, as well as regulatory amortizations. See Note 10, Income Taxes, in the Notes to Condensed Consolidated Financial Statements in Item 1.—”Financial Statements,” for more information.
LIQUIDITY AND CAPITAL RESOURCES
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, repairs from major storm damage, 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 (dollars in millions):

| Nine Months Ended September 30,
| 2021 |  | 2020
Cash and cash equivalents, beginning of period | $ | 257 |  |  | $ | 30 |
Net cash provided by (used in): |  |  |
Operating activities | 582 |  |  | 442 |
Investing activities | (502) |  |  | (551) |
Financing activities | (43) |  |  | 332 |
Increase (decrease) in cash and cash equivalents | 37 |  |  | 223 |
Cash and cash equivalents, end of period | $ | 294 |  |  | $ | 253 |

Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the nine months ended September 30, 2021 compared with the nine months ended September 30, 2020 (dollars in millions):
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| Increase/ (Decrease)
Net income | $ | 75 |
Margin deposits from wholesale counterparties | 102 |
Deferral of incremental storm costs | (58) |
Accounts payable and accrued liabilities | 37 |
Accounts receivable, net | (5) |
Margin deposits | 9 |
Decoupling | 23 |
Deferred income tax | 31 |
Depreciation and amortization | (15) |
Other | (59) |
Net change in cash flow from operations | $ | 140 |

The net change in cash flows from operations was primarily driven by an increase in net income of $75 million largely due to the previously reported energy trading losses recognized in 2020 that did not recur in 2021, an increase in margin deposits from wholesale counterparties of $102 million primarily due to PGE’s natural gas derivative asset positions as of September 30, 2021 as a result of commodity market conditions, offset by a $58 million decrease related to the February 2021 ice storms.
PGE estimates that non-cash charges for depreciation and amortization in 2021 will range from $410 million to $430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $575 million to $625 million. For additional information, see “Contractual Obligations” in this Liquidity and Capital Resources section of Item 2.
Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission and generation facilities. Net cash used in investing activities for the nine months ended September 30, 2021 decreased $49 million when compared with the nine months ended September 30, 2020, due to Wheatridge being constructed and placed in-service in 2020, partially offset by an increase in capital expenditures related to the IOC and winter storm restoration.
Excluding AFDC, the Company plans to make capital expenditures of $700 million in 2021, which it expects to fund with cash to be generated from operations during 2021, as discussed above, and the issuance of short- and long-term debt securities. For additional information, see “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.
Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the nine months ended September 30, 2021, net cash used in financing activities was primarily the result of the issuance of $400 million in First Mortgage Bonds, $160 million of payments on long-term debt, the issuance of a new 364-day term loan of $200 million, $350 million in repayments of short-term debt, payment of $112 million of dividends, and repurchase of common stock of $12 million.
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Capital Requirements
The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2021 through 2025 (dollars in millions, excluding AFDC).

| 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025
Ongoing capital expenditures* | $ | 630 |  |  | $ | 630 |  |  | $ | 550 |  |  | $ | 550 |  |  | $ | 550 |
Integrated Operations Center | 70 |  |  | 25 |  |  | — |  |  | — |  |  | — |
Total capital expenditures | $ | 700 |  |  | $ | 655 |  |  | $ | 550 |  |  | $ | 550 |  |  | $ | 550 |
Long-term debt maturities | $ | 160 |  |  | $ | — |  |  | $ | — |  |  | $ | 80 |  |  | $ | — |

* 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.
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, such as the 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 2021, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $575 million to $625 million, issuances of long-term debt securities of up to $400 million, and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments.
Short-term Debt. Pursuant to an order issued by the Federal Energy Regulatory Commission on January 16, 2020, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2022. The following table shows available liquidity as of September 30, 2021 (in millions):

| As of September 30, 2021
| Capacity |  | Outstanding |  | Available
Revolving credit facility (1) | $ | 650 |  |  | $ | — |  |  | $ | 650 |
Letters of credit (2) | 220 |  |  | 78 |  |  | 142 |
Total credit | $ | 870 |  |  | $ | 78 |  |  | $ | 792 |
Cash and cash equivalents |  |  |  |  | 294 |
Total liquidity |  |  |  |  | $ | 1,086 |

(1)Scheduled to expire September 2026.
(2)P GE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year.
On September 10, 2021, PGE amended and restated its existing revolving credit facility. As of September 30, 2021, PGE had a $650 million unsecured revolving credit facility scheduled to expire in September 2026. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. In addition, the Credit Facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify
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as black, indigenous, and people of color. 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 remaining term of the applicable credit facility.
The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of September 30, 2021, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $650 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time.
On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan bore interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to the terms of the loan. The term loan was paid off on September 30, 2021 with proceeds from a first mortgage bond issuance.
Long-term Debt. As of September 30, 2021, total long-term debt outstanding, net of $14 million of unamortized debt expense, was $3,285 million.
On January 6, 2021, the Company made a scheduled $140 million repayment of a 2.51% Series of First Mortgage Bonds with available cash.
On August 11, 2021, the Company made a scheduled $20 million repayment of a 9.31% Series of First Mortgage Bonds with available cash.
On September 30, 2021, PGE issued $400 million in First Mortgage Bonds (FMBs). The Bonds consist of:
•a series, due in 2028 (the "2028 Bonds"), in the amount of $100 million that will bear an interest from its issuance date at an annual rate of 1.82%;
•a series, due in 2031 (the “2031 Bonds"), in the amount of $50 million that will bear an interest from its issuance date at an annual rate of 2.10%;
•a series, due in 2034 (the "2034 Bonds" and collectively with the 2028 Bonds and the 2031 Bonds, the "Other Bonds"), in the amount of $100 million that will bear an interest from its issuance date at an annual rate of 2.20%; and
•a series, due in 2051, (the "2051 Bonds") in the amount of $150 million that will bear an interest from its issuance date at an annual rate of 2.97%.
Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 44.9% and 45.0% as of September 30, 2021 and December 31, 2020, respectively.
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Credit Ratings and Debt Covenants
PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows:

| Moody’s |  | S&P
Issuer credit rating | A3 |  | BBB+
Senior secured debt | A1 |  | A
Commercial paper | P-2 |  | A-2
Outlook | Stable |  | Stable

In the event Moody’s or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits, which is included in Other current assets on the Company’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets.
As of September 30, 2021, PGE had posted $25 million of collateral with these counterparties, consisting of $5 million in cash and $20 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of September 30, 2021, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $74 million, and decreases to $26 million by December 31, 2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $142 million and decreases to $87 million by December 31, 2021 and to $69 million by December 31, 2022.
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 facilities would increase.
The indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on September 30, 2021, under the most restrictive issuance test in the Indenture, the Company could have issued up to $1 billion of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.
PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of September 30, 2021, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 56.4%.
Off-Balance Sheet Arrangements
PGE has no off-balance sheet arrangements, other than surety bonds and outstanding letters of credit, 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.
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PGE’s surety bond and letter of credit arrangements are described in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021, there have been no material changes outside the ordinary course of business as of September 30, 2021.
Contractual Obligations
PGE’s contractual obligations for 2021 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, 2020, filed with the SEC on February 19, 2021. For such obligations, there have been no material changes outside the ordinary course of business as of September 30, 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. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations or cash flows. 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, 2020, filed with the SEC on February 19, 2021.

Item 4. | Controls and Procedures.

Disclosure Controls and Procedures
PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2021, these disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting
There were no changes in PGE’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II - OTHER INFORMATION

Item 1. | Legal Proceedings.

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

Item 1A. | Risk Factors.

There have been no material changes to PGE’s risk factors set forth in in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021.

Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds.

PGE did not repurchase any shares of its common stock during the three-month period ended September 30, 2021.
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Item 5. | Other Information.

Appointment of New Director
On October 26, 2021, the Board of Directors of the Company (the “Board”) appointed Dawn L. Farrell to serve as a director of the Company, effective January 1, 2022.
Ms. Farrell, 61, was most recently the President and Chief Executive Officer of TransAlta Corporation (TransAlta) since 2012, before retiring in March of this year. Prior to serving as CEO of TransAlta, she held a variety of executive leadership positions at TransAlta and British Columbia Hydro & Power Authority (BC Hydro) including leading commercial operations and development at TransAlta and generation and engineering at BC Hydro.
The Board appointed Ms. Farrell to serve on the Nominating, Governance and Sustainability Committee and Finance Committee of the Board, effective January 1, 2022.
There are no arrangements or understandings between Ms. Farrell and any other persons pursuant to which she was selected as director and she is not a party to any transaction with the Company that would require disclosure under Item 404(a) of Regulation S-K.
Ms. Farrell will participate in the Company’s standard compensation program for non-employee directors.

Item 6. | Exhibits.

Exhibit Number | Description
3.1 | Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2 | Eleventh Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed February 15, 2019).
10.1 | Second Amended and Restated Credit Agreement, dated as of September 10, 2021, among Portland General Electric Company, the Lenders, and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to PGE’s Current Report on Form 8-K filed September 14, 2021).
10.2 | Seventy-ninth Supplemental Indenture, dated September 15, 2021, between the Portland General Electric Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to PGE’s Current Report on Form 8-K, filed October 1, 2021).
31.1 | Certification of Chief Executive Officer.
31.2 | Certification of Chief Financial Officer.
32 | Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS | XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH | XBRL Taxonomy Extension Schema Document.
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB | XBRL Taxonomy Extension Label Linkbase Document.
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document.
104 | Cover page information from Portland General Electric Company’s Quarterly Report on Form 10-Q filed October 30, 2020, formatted in iXBRL (Inline Extensible Business Reporting Language).

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Certain instruments defining the rights of holders of other long-term debt of the Company are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  |  | PORTLAND GENERAL ELECTRIC COMPANY
|  |  | (Registrant)
Date: | October 28, 2021 |  | By: | /s/ James A. Ajello
|  |  |  | James A. Ajello
|  |  |  | Senior Vice President of Finance, Chief Financial Officer and Treasurer
|  |  |  | (duly authorized officer and principal financial officer)

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