# PORTLAND GENERAL ELECTRIC CO /OR/ (POR) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from PORTLAND GENERAL ELECTRIC CO /OR/'s 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/784977/000078497722000009/por-20211231.htm
Accession: 0000784977-22-000009
Filing date: 2022-02-17
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture.
Confidence: high

Company profile: /company/POR/
All MD&A years: /company/POR/mda/
Next year: /company/POR/mda/fy2022/ (FY 2022)

ITEM 7.     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

34

Table of Contents

structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, 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;

•inflation and interest rates;

•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 ESSs or community choice aggregators;

•the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 7. and Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K;

•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 PSPS and de-energize its system in the event of heightened wildfire risk, which could lead to potential liability if energized systems are involved in wildfires that cause harm;

•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;

•delays in the supply chain and increased supply costs, failure to complete capital projects on schedule and within budget, failure of counterparties to perform under agreements, or the abandonment of capital projects, any one 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;

35

Table of Contents

•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, whether global or local in nature, including unseasonable or extreme weather and other natural phenomena 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 growth, or demographic patterns, in PGE’s service territory;

•the effectiveness of PGE’s risk management policies and procedures;

•cybersecurity attacks, data security breaches, physical 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, vendor, employee, or Company information;

•employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and the ability to recruit and retain key employees and other talent due to COVID-19 mandates and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries since the beginning of the COVID-19 pandemic;

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

•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 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. MD&A should be read in conjunction with the Company’s 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 the wholesale market 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. PGE is committed to developing products and service offerings for the benefit of retail and wholesale

36

Table of Contents

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

The Company exists to power the advancement of society. PGE energizes lives, strengthens communities, and fosters energy solutions that promote social, economic, and environmental progress. The Company is committed to being a clean energy leader and delivering steady growth and returns to shareholders. PGE is focused on working with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing greenhouse gas emissions, and responding to evolving customer expectations. At the same time, the Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region. PGE is transforming all aspects of its business to empower its workforce to be even more results oriented to serve customers well. To create a clean energy future, PGE is focused on the following strategic initiatives:

•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.

Climate change

State-mandated GHG reduction targets— In June 2021, the Oregon legislature passed 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, and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see the “Environmental Laws and Regulations” section within this Overview.

In response to the state of Oregon’s GHG reduction targets to combat climate change, PGE estimates by 2030 it will need to acquire approximately 1,500 to 2,000 MW of clean and renewable resources and approximately 800 MW of non-emitting dispatchable capacity resources. For more information see “The Resource Planning Process” within Investing in a clean energy future section of this Overview.

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.

Empowering customers and communities—PGE’s customers are committed to purchasing clean energy, as over 235 thousand 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.

37

Table of Contents

In response, the Company implemented a new customer service option, the GFI Program, which allows for 100 MW of PGE-provided PPAs 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.

In December 2021, the OPUC issued an order, which approved a petition to increase capacity under the customer-provided renewable resources by 250 MW, which would bring the total available capacity under the program to 750 MW.

Extreme weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. In June 2021, temperatures in the region reached all-time recorded highs, shattering the Company’s previous peak load demand, and surpassing the prior summer peak load by nearly 12% (see the Operating Activities section of this Overview for more information on the impacts to PGE’s results of operation). In February 2021, PGE’s service territory experienced an ice storm, which led to historical levels of customer power outages, and caused considerable expense for service restoration and damage repair (see “February 2021 Ice Storms and Damage” of the Regulatory Matters section of this Overview for more information on the impact to PGE’s results of operation). In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned (see “Wildfire” of the Regulatory Matters section of this Overview for more information on the impact to PGE’s results of operation). The increase and severity of extreme weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.

Investing in a clean energy future

Building a resilient grid— Recent extreme weather events driven by changes to global systems affecting rainfall patterns and seasonal snow cover in the region have impacted PGE’s customers significantly, and the frequency and severity of these events are accelerating. PGE’s grid of the future is increasingly smart and adaptive, so that the electric service its customers depend on remains reliable even under uncertain and extreme conditions. For example, the Company uses wireless smart sensors and centrally controlled automated switches to help isolate disruptions and more quickly reroute power, preventing or shortening disruptions. In the field, PGE uses advanced data analytics to optimize system investments and maintenance. The Company is updating its design standards, so that smart sensors and switches are constructed to withstand more extreme weather, particularly in high-risk wildfire areas. Highlights of PGE’s key investments and plans for building a resilient grid are as follows:

•Integrated Operations Center (IOC) — In the fourth quarter of 2021, PGE placed in-service the IOC with a total investment of $175 million, including an allowance for funds used during construction (AFUDC). 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. 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.

•Advanced Distribution Management System (ADMS) – In the fourth quarter of 2021, PGE placed in-service a new software platform called the ADMS with a total investment of $30 million. The ADMS 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.

38

Table of Contents

•Distribution System Plan (DSP) - PGE filed its inaugural DSP on October 15, 2021, which lays out plans to build a grid that empowers customers to make energy management choices to support decarbonization and supports a two-way energy ecosystem with resources like batteries, two-way EV charging, and solar panels where communities—especially underserved Oregonians—need them.

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 (RFP) seeking to procure approximately 100 average megawatts (MWa) of qualifying renewable resources. The prevailing 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 completed in early 2022. 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 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

•CTWS—As of December 31, 2021, PGE had 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 CTWS. The CTWS had an option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte in 2021, and closed on the purchase of this incremental undivided ownership interest on January 1, 2022. As a result, PGE’s ownership interest in the project is 50.01%. 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. For more information see “CTWS” within Purchased Power in the Power Supply section of Item 1.—“Business.”

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 currently 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 Colstrip 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;

39

Table of Contents

•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

•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.

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 issued the final RFP after receiving approval from the OPUC in December 2021, with a submission deadline for proposals in January 2022. The RFP seeks to add 375 to 500 MW of renewables and 375 MW of non-emitting capacity by the end of 2024. Among the conditions, the OPUC will require PGE to consider bid submissions that would propose to repower existing generation resources. Bids will be evaluated based on the OPUC-approved scoring methodology. Following determination of a final shortlist, PGE plans to file for acknowledgement during April 2022 with a final selection in June.

On October 15, 2021, PGE filed an extension waiver for the next IRP, which the OPUC approved. As a result, the next IRP would be filed for OPUC consideration by March 31, 2023.

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;

•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.

The Company is also working to advance transportation electrification, partnering with local mass transit agencies to transition to a greater use of electric vehicles, and developing projects aimed at improving accessibility to electric vehicle charging stations. In June 2019, the Oregon Legislature enacted Oregon Senate Bill 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.

PGE also partnered with Daimler Trucks North America to open Electric Island, a first-of-its-kind heavy-duty electric truck charging site. The project is also one of the first sites deployed in the multi-utility, I-5 transit Corridor Project that will install heavy duty electric vehicle charging stations along I-5 from Canada to Mexico. In addition, PGE is working with the City of Portland to install charging systems on existing power poles, and the Company helped bring the first electric school buses to Oregon’s roads.

Environmental Laws and Regulations

40

Table of Contents

House Bill 2021—In June 2021, the Oregon Legislature passed HB 2021, which requires retail electricity providers to reduce GHG emissions associated with electricity sold to Oregon consumers to 80% below baseline emissions levels by 2030, 90% below baseline emissions levels by 2035, and 100% below baseline emissions levels by 2040. 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 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 ESSs;

•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 kilowatts and smaller and allows utilities the ability to earn a return on investments in program resources, and

•Codifies non-bypassability of costs to ensure all customers pay their share of HB 2021 policy costs.

Governor Executive Orders—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 did 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 emissions 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 emissions 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.

41

Table of Contents

•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. The ODEQ adopted such a program, referred to as the Climate Protection Plan, on December 16, 2021; and

•More than doubled the reduction goals of the state’s Clean Fuels Program and extended the program, from the previous rule that required a ten percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.

RPS Standards and Other Laws—In 2016, 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 RAC filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE’s investment in Colstrip 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 by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in their respective jurisdictions. In December 2021, the OPUC approved PGE’s depreciation study (OPUC Docket UM 2152), which will accelerate depreciation on Colstrip through December 31, 2025. Depreciation rates will change and customer collection would coincide with the price effective date of the Company’s pending 2022 General Rate Case (2022 GRC). For further information on the 2022 GRC, see “General Rate Case” in the “Regulatory Matters” section of this Overview. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of PGE’s exit from the facility. See Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” 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.

For a more comprehensive review of Environmental Matters, see “Environmental Matters” in Item 1.—Business.

Regulatory Matters

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

42

Table of Contents

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. 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 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, as well as the new IOC and ADMS software platform (see “Building a resilient grid” section of Investing in a clean energy future within this Overview.)

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 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 2022 GRC was 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 reached an agreement that resolves cost of capital issues and 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.

In addition, on January 18, 2022, PGE, OPUC staff, and certain customer groups filed a stipulation with the OPUC reflecting an agreement that resolves the annual revenue requirement, average rate base, and corresponding increase authorized in customer prices. Certain elements of the case remain unsettled.

The latest agreement reflects a final revenue requirement that is based upon an average rate base of $5.6 billion and an annual revenue requirement increase of $74 million consisting of the following changes (in millions):

43

Table of Contents

[[GREPCENT_TABLE]]
[["As filed (includes $40 million related to Net Variable Power Costs)","","","$","99"],["Load and Net Variable Power Cost Updates","","","16"],["Base Business Revenue Requirement Updates:"],["Faraday hydro capital-related revenue requirement (1)","","(18)"],["Cost of debt settlement including reductions to reflect actual financing costs","","(7)"],["Level III outage annual regulatory accrual (2)","","(7)"],["Other reductions to rate base and O&M","","(5)"],["Other various modifications to reflect actual costs","","(4)"],["Subtotal","","","(41)"],["As revised (includes $64 million related to Net Variable Power Costs) (3)","","","$","74"]]
[[/GREPCENT_TABLE]]

(1) The Faraday improvement capital project will not be placed in-service as of May 9, 2022, and the capital-related revenue requirement has been removed and will be addressed in future ratemaking proceedings. As of December 31, 2021, the CWIP balance associated with Faraday was $109 million, including AFUDC.

(2) PGE is authorized to collect annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In the 2022 GRC, the Company requested an annual collection increase from $4 million to $11 million, and agreed to retain the annual collection at $4 million.

(3) Total revenue requirement increase to base rates is $83 million, of which $9 million is not considered incremental as it is already included in current customer prices.

Further, the agreement with parties would eliminate PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to this case. In 2022, estimated collections from, or refunds to, customers will be pro-rated based on the effective date of new customer prices per the 2022 GRC and expected to be amortized in customer prices in 2024 over a one-year period. The decoupling mechanism provides a means of recovery or refund of margin lost or gained as a result of changes in weather-adjusted energy use per customer in comparison to levels projected in customer prices. For further information on the decoupling mechanism, see “Decoupling” in this Overview section.

All the agreements remain subject to OPUC approval. PGE will continue to work with parties throughout this proceeding to resolve all remaining unsettled elements of the case.

PGE has proposed that new customer prices become effective May 9, 2022. Price changes for the AUT and the supplemental schedule items occurred January 1, 2022.

Regulatory review of the 2022 GRC will continue, with a final OPUC order expected to be issued by April 2022. Management cannot predict the ultimate outcome of the case.

More information about the 2022 GRC filing (OPUC Docket UE 394) is available on the OPUC Internet 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.

In March 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 that may qualify for deferral under

44

Table of Contents

Docket UM 2114. 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. In September 2020, the OPUC 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 OPUC in October 2020 with final stipulations for the Term Sheet approved in November 2020.

For the year ended December 31, 2021, PGE recorded a $26 million net increase to its COVID-19 deferral. As of December 31, 2021 and December 31, 2020, PGE’s deferred balance was $36 million and $10 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. Incremental bad debt expense was $29 million for the year ending 2021. 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. The OPUC’s conclusion of overall prudence, including an earnings review, 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.

In June 2020, the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative AFUDC 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 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.

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. Pursuant to Oregon Senate Bill 762, which was passed in June 2021, PGE submitted a risk-based wildfire protection plan to the OPUC in December 2021.

PGE continues to incur costs to replace and rebuild PGE facilities damaged by the fires that occurred in 2020, 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. In October 2020, the OPUC formally approved PGE’s request for deferral of such costs. As of December 31, 2021 and December 31, 2020, PGE’s cumulative deferred costs related to the wildfire response was $45 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. The OPUC’s conclusion of overall prudence, including an earnings review,

45

Table of Contents

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.

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 December 31, 2021, PGE has incurred an estimated $105 million in incremental costs due to the storms, of which $36 million were capital and recorded to Electric utility plant, net and $69 million were operating expenses 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. In December 2021, PGE and parties in the 2022 GRC reached a settlement, subject to OPUC approval, to restore the storm collection balance for the $9 million used in 2021 and to defer the resulting balance of $9 million into the February 2021 ice storm and damage regulatory asset.

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 December 31, 2021, the Company has deferred a total of $67 million, including interest, related to incremental operating expenses due to the storms. PGE incurred and deferred costs 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 expects an OPUC decision on the February storms deferral in the first quarter of 2022. While the Company believes the full amount of the deferral is probable of recovery given 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. The OPUC’s conclusion of overall prudence, including an earnings review, 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 would include 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, 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. As of December 31, 2021, PGE has not recorded any costs under this deferral order.

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. The 2022 AUT contains a $64 million increase in NVPC that will be recovered in customer prices beginning January 1, 2022. For 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, as of December 31, 2021, PGE has deferred $29 million, which represents 90% of the excess variance expected to be collected from customers. See “Power Operations” within this Overview section of Item 7 for more information regarding the PCAM.

46

Table of Contents

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 December 31, 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 an 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 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 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

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.

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.

In the 2022 GRC, parties reached an agreement that would eliminate PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to the case, which are expected to begin in May 2022. Subject to approval by the OPUC, which is expected in a final order by April 2022, deferrals would cease, although amortization of previously recorded deferrals would continue as scheduled until collected or refunded in future customer prices.

For the year ended December 31, 2021, the Company recorded an estimated refund of $17 million and a collection of $7 million from residential and commercial customers, respectively, that resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company continues 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.

At December 31, 2020, PGE had recorded a total refund of $6 million that will be refunded to customers over a one-year period, which began January 1, 2022.

47

Table of Contents

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 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 2022 GRC proceeding. The Administrative Law Judge denied the consolidation, although did provide an opportunity to use the 2022 GRC proceeding to settle any issues with deferrals. How the Boardman deferral will be resolved in relation to the 2022 GRC proceeding remains uncertain and management is currently unable to predict the outcome. PGE continues to work with the OPUC and parties to establish an appropriate schedule and process to allow for a fair determination of the Boardman deferral and the 2022 GRC.

Pursuant to the deferral application, PGE estimates the potential deferral to be $14 million for the period ended December 31, 2020 plus an additional $66 million for the year ended December 31, 2021. As of December 31, 2021, 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 continued 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.

Depreciation Study—In December 2021, PGE received an OPUC order approving revised depreciation rates based on 2019 data. The new rates will be incorporated in PGE’s 2022 GRC and expected to be effective May 9, 2022.

The OPUC order also approved the acceleration of depreciation expense and corresponding recovery on Colstrip generation assets from December 31, 2030 to December 31, 2025. The resulting depreciation rates are expected to go into effect when new customer prices go into effect in May 2022, in conjunction with the 2022 GRC.

The order also includes cost recovery of $4 million for updated ARO-related decommissioning costs related to PGE’s T.W. Sullivan hydro generating facility. In 2020, PGE had updated its ARO costs resulting in cumulative ARO expenses of $4 million being recognized. At the time PGE did not establish a regulatory asset, as probability of recovery in the depreciation study was not yet considered probable. Because the OPUC’s order on the depreciation study includes recovery of the ARO, PGE established a regulatory asset and ARO balancing account, resulting in a credit to earnings of $4 million for the year ended December 31, 2021. For more information on PGE’s AROs, see Critical Accounting Policies and Estimates in this Item 7., and see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Renewable Recovery Framework—As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 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.

Operating Activities

In combination with electricity provided by PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, the Company purchases and sells electricity in the wholesale market. The Company also performs portfolio management and wholesale market sales services for third parties in the region. PGE participates in the western EIM, which allows the Company to, among other things, integrate more

48

Table of Contents

renewable energy into the grid by better matching the variable output of renewable resources. PGE is committed to developing products and service offerings for the benefit of retail and wholesale customers. 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. During the summer of 2021, demand reached a new all-time high, surpassing the previous mark, which was a winter peak. See “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” for further information regarding seasonal fluctuations. Retail customer price changes and customer usage patterns, which can be affected by the economy and recently, by changes due to COVID-19 restrictions, 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 2021 and 2020.

[[GREPCENT_TABLE]]
[["Energy deliveries (MWh in thousands)","","","2021","","","","2020","","% Increase/ (Decrease)"],["Retail:"],["Residential","","","7,978","","","","","7,756","","","2.9","%"],["Commercial (PGE sales only)","","","6,604","","","","","6,222","","","6.1"],["Direct Access","","","589","","","","","633","","","(7.0)"],["Total Commercial","","","7,193","","","","","6,855","","","4.9"],["Industrial (PGE sales only)","","","3,714","","","","","3,446","","","7.8"],["Direct Access","","","1,647","","","","","1,486","","","10.8"],["Total Industrial","","","5,361","","","","","4,932","","","8.7"],["Total (PGE sales only)","","","18,296","","","","","17,424","","","5.0"],["Total Direct Access","","","2,236","","","","","2,119","","","5.5"],["Total retail energy deliveries","","","20,532","","","","","19,543","","","5.1","%"],["Wholesale energy deliveries","","","5,946","","","","","5,794","","","2.6"],["Total energy deliveries","","","26,478","","","","","25,337","","","4.5","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["Average number of retail customers","","2021","","2020","","% Increase/ (Decrease)"],["Residential","","800,372","","","88","%","","791,119","","","88","%","","1.2","%"],["Commercial","","111,062","","","12","","","110,290","","","12","","","0.7"],["Industrial","","191","","","\u2014","","","194","","","\u2014","","","(1.5)"],["Direct access","","584","","","\u2014","","","634","","","\u2014","","","(7.9)"],["Total","","912,209","","","100","%","","902,237","","","100","%","","1.1","%"]]
[[/GREPCENT_TABLE]]

In 2021, retail energy deliveries increased 5.1% from 2020, with increases reflected in all three customer classes, as the region experienced a recovery from the COVID-19 downturn seen in 2020. Commercial and industrial classes experienced growth associated with economic recovery and, with COVID-19 variants continuing to impact consumer behavior, residential usage remained elevated.

49

Table of Contents

In March 2020, the Governor of Oregon issued an order directing residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact would be difficult or impossible to avoid. The Company saw a shift in retail demand in response, beginning with the second quarter of 2020. In particular, residential loads increased 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 have closed as a result of the lack of business as residents followed directives from state and federal authorities. The majority of state and local mandates were lifted by mid-2021, allowing for commercial recovery to begin, however as COVID-19 variants impacted communities in 2021, impacts to energy deliveries, particularly increases in residential average usage remain.

Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 2.9% higher in 2021 than 2020, due to a 1.7% increase in average usage per customer, which resulted largely from warmer summer temperatures, and a 1.2% increase in the average number of customers. In 2021, the Company’s service territory experienced warmer temperatures during the cooling season than in 2020, indicating higher demand for cooling.

Commercial energy deliveries increased 4.9% overall with widespread increases across PGE’s customer base as many sectors impacted by COVID-19 related closures and economic conditions, including government and education, miscellaneous commercial, and lodging, began to recover.

Industrial energy deliveries increased 8.7% in 2021 due to continued strength in the high-tech manufacturing sector.

Total heating degree-days, an indication of electricity use for heating, in 2021 were 7% below the 15-year average although fairly consistent overall with total heating degree-days in 2020. Total cooling degree-days, a similar indication of the extent to which customers are likely to have used electricity for cooling, in 2021, exceeded the 15-year average by 52% and were 40% above the 2020 total. The following table presents the number of heating and cooling degree-days in 2021 and 2020, along with the current 15-year averages, reflecting the influence that weather had on comparative energy deliveries, most notably in the 2nd and 3rd quarters:

[[GREPCENT_TABLE]]
[["","Heating Degree-Days","","Cooling Degree-Days"],["","2021","","2020","","15-Year Average","","2021","","2020","","15-Year Average"],["1st quarter","1,805","","","1,761","","","1,847","","","\u2014","","","\u2014","","","\u2014"],["2nd quarter","498","","","554","","","629","","","238","","","99","","","93"],["3rd quarter","54","","","47","","","74","","","600","","","492","","","455"],["4th quarter","1,471","","","1,474","","","1,570","","","\u2014","","","9","","","2"],["Total","3,828","","","3,836","","","4,120","","","838","","","600","","","550"],["Increase (decrease) from the 15-year average","(7)","%","","(7)","%","","","","52","%","","9","%"]]
[[/GREPCENT_TABLE]]

On a weather-adjusted basis, total retail deliveries increased 4.0% from 2020. The increase was driven by an 8.5% growth in industrial deliveries and 4.2% growth in commercial energy deliveries, in addition to a 1.0% increase in weather-adjusted deliveries to residential customers, which was driven by the growth in customer count. PGE expects retail energy deliveries for 2022 will continue to be impacted by COVID-19 related behavioral changes. PGE projects that retail energy deliveries for 2022 will be 2.0 to 2.5% above 2021 weather-adjusted levels, reflecting strength in industrial deliveries, and impacts associated with COVID-19 early in the year, and unwinding of such impacts later in the year.

ESSs supplied Direct Access customers with energy representing 11% of the Company’s total retail energy deliveries during 2021 and 2020. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 13% of the Company’s total retail energy deliveries for 2021. With

50

Table of Contents

the adoption of the New Large Load Direct Access program in 2020, as much as 18% of the Company’s 2021 energy deliveries could have been supplied by ESSs.

Power Operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. 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 generation portfolio.

[[GREPCENT_TABLE]]
[["","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"],["Thermal:"],["Natural gas","89","%","92","%","","","114","%","74","%","","48","%","43","%"],["Coal (3)","\u2014","","99","","","","103","","83","","","11","","17"],["Wind","92","","94","","","","110","","117","","","12","","11"],["Hydro","83","","86","","","","73","","71","","","6","","7"]]
[[/GREPCENT_TABLE]]

(1)Plant availability represents the percentage of the year 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 81% in 2021, compared with 74% in 2020. Boardman ceased coal-fired generation on October 15, 2020.

Energy received from PGE-owned and jointly-owned thermal plants in 2021 compared to 2020 remained materially consistent. In 2021, production at the Company’s natural gas-fired plants increased to help meet retail load demands and offset a decrease in coal-fired generation as a result of Boardman ceasing operation in October 2020. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year.

Total energy received from all hydroelectric sources, both PGE-owned generation and purchased, increased 14% in 2021 compared to 2020. Energy received from mid-Columbia and other regional hydroelectric projects increased 22% in 2021 due to new PPAs in place in 2021 as compared to 2020. The energy generated by the Company-owned facilities decreased 11% 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 7, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 30% in 2021 compared to 2020 primarily due to the addition of Wheatridge during the fourth quarter of 2020 and more favorable wind conditions. 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.

51

Table of Contents

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 2021 and 2020:

•For 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the PCAM, as PGE’s preliminary regulatory ROE was below 8.5% pursuant to the related earnings test, as of December 31, 2021, PGE has deferred $29 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. The OPUC’s conclusion of overall prudence, including an earnings review, 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 2020, excluding certain trading losses totaling $127 million, for which PGE did not pursue recovery from customers, actual NVPC was below baseline NVPC by $13 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2020. A final determination regarding the 2020 PCAM results was made by the OPUC through a public filing and review in 2021, which confirmed no refund to customers pursuant to the PCAM for 2020. For further information regarding trading losses, see “Actual NVPC” in the Results of Operations section of this Item 7.

The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $79 million increase was expected in 2021 over 2020. The 2022 AUT anticipates a $64 million increase in NVPC that will be recovered in customer prices beginning January 1, 2022.

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.

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

52

Table of Contents

[[GREPCENT_TABLE]]
[["","Years Ended December 31,","","% Increase (Decrease)"],["","2021","","2020"],["","Amount","","Amount"],["Total revenues","$","2,396","","","$","2,145","","","12","%"],["Operating expenses:"],["Purchased power and fuel","822","","","708","","","16"],["Generation, transmission and distribution","310","","","293","","","6"],["Administrative and other","336","","","283","","","19"],["Depreciation and amortization","404","","","454","","","(11)"],["Taxes other than income taxes","146","","","138","","","6"],["Total operating expenses","2,018","","","1,876","","","8"],["Income from operations","378","","","269","","","41"],["Interest expense, net *","137","","","136","","","1"],["Other income:"],["Allowance for equity funds used during construction","17","","","16","","","6"],["Miscellaneous income, net","9","","","6","","","50"],["Other income, net","26","","","22","","","18"],["Income before income taxes","267","","","155","","","72"],["Income tax expense","23","","","\u2014","","","\u2014"],["Net income","$","244","","","$","155","","","57","%"]]
[[/GREPCENT_TABLE]]

* Includes an allowance for borrowed funds used during construction of $8 million in both 2021 and 2020.

2021 Compared to 2020

Net income for 2021 increased $89 million from 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, particularly during the third quarter of 2021, after removing the impact of the previously reported energy trading losses of $127 million 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, and interest income on Regulatory Assets. Higher Administrative and general expenses reflect increases for employee wage and benefit expenses and outside services, including labor. Generation, transmission and distribution expenses increased largely from wildfire mitigation efforts, vegetation management, and storm restoration expenses.

Total revenues consist of the following for the years presented (in millions):

53

Table of Contents

[[GREPCENT_TABLE]]
[["","2021","","2020","","% Increase (Decrease)"],["Retail: (1)"],["Residential","$","1,118","","","$","1,030","","","9","%"],["Commercial","690","","","616","","","12"],["Industrial","250","","","218","","","15"],["Direct Access","47","","","46","","","2"],["Subtotal","2,105","","","1,910","","","10"],["Alternative revenue programs, net of amortization","(29)","","","(6)","","","383"],["Other accrued revenues, net (2)","2","","","28","","","(93)"],["Total retail revenues","2,078","","","1,932","","","8"],["Wholesale revenues","255","","","162","","","57"],["Other operating revenues","63","","","51","","","24"],["Total revenues","$","2,396","","","$","2,145","","","12","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["(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. Commercial revenues from ESS customers were $18 million for 2021 and 2020. Industrial revenues from ESS customers were $29 million and $28 million for 2021 and 2020, respectively."],["(2)","Amount for the year ended December 31, 2020 is primarily comprised of $24 million of amortization, including interest, related to the net tax benefits due to the change in corporate tax rate under the TCJA."]]
[[/GREPCENT_TABLE]]

Total retail revenues—The following items contributed to the increase in Total retail revenues for the year ended December 31, 2021 compared to the year ended December 31, 2020 (dollars in millions):

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","1,932"],["Retail energy deliveries driven by higher industrial demand, the impact of COVID-19 resulting in higher residential demand, and the increase due to the effects of weather","94"],["Increase as a result of the AUT, approved by the OPUC, for higher anticipated power costs","67"],["Increase due to the RAC, as approved by the OPUC for Wheatridge placed into service","23"],["Alternative revenue programs related to the decoupling mechanism deferrals due to increased residential use per customer resulting from COVID-19","(7)"],["Combination of various supplemental tariffs and adjustments","(12)"],["Average price of energy deliveries due primarily to variation in usage among customer classes resulting from COVID-19","(19)"],["Year ended December 31, 2021","$","2,078"],["Change in Total retail revenues","$","146"]]
[[/GREPCENT_TABLE]]

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.

In 2021, a $93 million, or 57%, increase from 2020 in wholesale revenues resulted from an $89 million increase from a 53% increase in average prices received when the Company sold power into the wholesale market and a $4 million increase related to a 3% increase in wholesale sales volume. Wholesale prices for electricity increased as a result of more extreme weather experienced during 2021 than was typical for the region, less hydro generation, and reduced regional capacity.

Other operating revenues increased $12 million, or 24%, in 2021 from 2020, primarily as a result of a $9 million increase due to market conditions that provided more revenue from the resale of natural gas back into the wholesale

54

Table of Contents

market in excess of amounts needed for the Company’s generation portfolio. Natural gas prices were considerably higher in the first quarter of 2021 due in part to the impact of unusual weather events on the demand for natural gas.

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 increase in Purchased power and fuel for the year ended December 31, 2021 compared to the year ended December 31, 2020 (dollars in millions, except for average variable power cost per MWh):

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","708"],["Average variable power cost per MWh","99"],["Total system load","44"],["PCAM deferral","(29)"],["Year ended December 31, 2021","$","822"],["Change in Purchased power and fuel","$","114"],["Average variable power cost per MWh:"],["Year ended December 31, 2020","$","29.14"],["Year ended December 31, 2021","$","33.63"],["Total system load (MWh in thousands):"],["Year ended December 31, 2020","24,286"],["Year ended December 31, 2021","25,295"]]
[[/GREPCENT_TABLE]]

For the year ended December 31, 2021, the $99 million increase related to the change in average variable power cost per MWh was primarily driven by a 20% increase in the average cost for purchased power due largely to purchases made at peak market prices to meet customer demand during the summer, partially offset by a 2% decrease in the average cost of power from the Company’s own generation. The $43 million increase related to total system load was primarily due to a 9% increase in purchased power, driven largely by increased customer demand due to weather and load growth, as well as a 1% increase in the company’s own generation.

PGE’s sources of energy, total system load, and retail load requirement for the years presented are as follows:

55

Table of Contents

[[GREPCENT_TABLE]]
[["","Years Ended December 31,"],["","2021","","2020"],["Sources of energy (MWh in thousands):"],["Generation:"],["Thermal:"],["Natural gas","9,306","","","37","%","","8,029","","","33","%"],["Coal","2,060","","","8","","","3,232","","","13"],["Total thermal","11,366","","","45","","","11,261","","","46"],["Hydro","1,073","","","4","","","1,204","","","5"],["Wind","2,316","","","9","","","2,111","","","9"],["Total generation","14,755","","","58","","","14,576","","","60"],["Purchased power:"],["Hydro*","4,789","","","19","","","3,936","","","16"],["Wind*","989","","","4","","","426","","","2"],["Solar*","501","","","2","","","414","","","2"],["Natural Gas","63","","","\u2014","","","38","","","\u2014"],["Waste, Wood and Landfill Gas*","167","","","1","","","174","","","1"],["Source not specified","4,031","","","16","","","4,722","","","19"],["Total purchased power","10,540","","","42","","","9,710","","","40"],["Total system load","25,295","","","100","%","","24,286","","","100","%"],["Less: wholesale sales","(5,946)","","","","","(5,794)"],["Retail load requirement","19,349","","","","","18,492"]]
[[/GREPCENT_TABLE]]

*Includes power received from PURPA qualifying facilities of 15 MWh in 2021 and 17 MWh in 2020 from Hydro resources, 30 MWh in 2021 and 33 MWh in 2020 from Wind resources, 472 MWh in 2021 and 383 MWh in 2020 from Solar resources, and 102 MWh in 2021 and 93 MWh in 2020 from Waste, Wood and Landfill Gas resources.

The following table presents the forecasted April-to-September 2022 and actual April-to-September 2021 and 2020 runoff at particular points of major rivers relevant to PGE’s hydro resources:

[[GREPCENT_TABLE]]
[["","Runoff as a Percent of Normal*"],["Location","2022 Forecast","","2021 Actual","","2020 Actual"],["Columbia River at The Dalles, Oregon","105","%","","82","%","","104","%"],["Mid-Columbia River at Grand Coulee, Washington","108","","","89","","","109"],["Clackamas River at Estacada, Oregon","97","","","70","","","75"],["Deschutes River at Moody, Oregon","97","","","84","","","86"]]
[[/GREPCENT_TABLE]]

* 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, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $21 million in 2021 compared with 2020. The increase attributable to changes in Purchased power and fuel expense was the result of a 15% increase in the average variable power cost per MWh and a 4% increase in total system load. The increase in actual NVPC was also a result of the 53% higher average price per MWh sold and a 3% increase in the volume of wholesale energy deliveries.

56

Table of Contents

The following items contributed to the increase in Actual NVPC for the year ended December 31, 2021 compared to the year ended December 31, 2020 (in millions):

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","546"],["Purchased power and fuel expense","143"],["Wholesale revenues","(93)"],["PCAM Deferral","(29)"],["Year ended December 31, 2021","567"],["Change in NVPC","$","21"]]
[[/GREPCENT_TABLE]]

For further information regarding NVPC in relation to the PCAM, see “Power Operations” in the Overview section of this Item 7.

Energy Trading—PGE personnel entered into a number of energy trades during 2020, resulting in significant exposure to the Company. In August 2020, a portion of energy trading positions in PGE’s energy portfolio experienced significant losses as wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. During this time period, the CAISO declared a Stage 3 Electrical Emergency and ordered the first rolling blackouts in the state of California since 2001. As a result of the convergence of these conditions, the Company’s energy portfolio experienced realized losses of $127 million on these positions in 2020. PGE did not pursue recovery of the energy trading losses, and the increase in net variable power costs due to this trading activity was recognized in PGE’s results of operations. PGE no longer has net market exposure from the energy trading positions that led to these losses.

Generation, transmission, and distribution

The following items contributed to the $17 million or 6% increase in Generation, transmission and distribution for the year ended December 31, 2021 compared to the year ended December 31, 2020 (in millions):

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","293"],["Decrease primarily due to lower maintenance expense as the result of reduced run hours and lower long-term service agreement costs at some of the Company\u2019s generation facilities","(20)"],["Higher storm restoration and wildfire risk mitigation expenses","19"],["Higher vegetation management and line maintenance expenses","8"],["Miscellaneous expenses","10"],["Year ended December 31, 2021","310"],["Change in Generation, transmission and distribution","$","17"]]
[[/GREPCENT_TABLE]]

PGE deferred $69 million of incremental costs for year ended December 31, 2021, related to February 2021 ice storm damage in PGE’s service territory. See the “Overview” section of this Item 7., for more information.

Administrative and other

The following items contributed to the $53 million or 19% increase in Administrative and other for the year ended December 31, 2021 compared to the year ended December 31, 2020 (in millions):

57

Table of Contents

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","283"],["Higher professional and contracted services","23"],["Wage and benefits expenses","20"],["Miscellaneous expenses","10"],["Year ended December 31, 2021","336"],["Change in Administrative and other","$","53"]]
[[/GREPCENT_TABLE]]

In 2021, PGE experienced higher Generation, transmission, and distribution and Administrative and other expenses due to inflation in labor and other operating expenses. The Company believes it is reasonably likely that this trend may continue in 2022 and could have a material impact on its results of operations. PGE’s ongoing focus on cost management and operational efficiencies is expected to help mitigate inflation.

Depreciation and amortization

The following items contributed to the $50 million or 11% decrease in Depreciation and amortization for the year ended December 31, 2021 compared to year ended December 31, 2020 (in millions):

[[GREPCENT_TABLE]]
[["Year ended December 31, 2020","$","454"],["ARO revisions","(28)"],["Capital retirements, net of additions","(12)"],["Activity related to regulatory programs (offset elsewhere on the income statement)","(10)"],["Year ended December 31, 2021","404"],["Change in Depreciation and amortization","$","(50)"]]
[[/GREPCENT_TABLE]]

See “Depreciation Study” within “Regulatory Matters” in the Overview section of this Item 7., for more information regarding revisions made to non-utility AROs.

Taxes other than income taxes expense increased $8 million, or 6%, in 2021 compared with 2020, primarily due to higher Oregon property taxes and franchise fees.

Interest expense increased $1 million, or 1%, in 2021 compared with 2020 driven by higher average balances of outstanding debt.

Other income, net increased $4 million, or 18%, in 2021 compared to 2020, with the difference driven by higher regulatory interest income on deferred asset balances as well as higher AFUDC equity driven by higher construction work-in-progress balances in 2021.

Income tax expense increased $23 million in 2021 compared to 2020 primarily 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 12, Income Taxes, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements,” for more information.

2020 Compared to 2019

For a comparison of the Company’s results of operations for the fiscal year ended December 31, 2020 to the year ended December 31, 2019, see Item 7.—” Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021.

58

Table of Contents

Liquidity and Capital Resources

Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan.” in Item 1A.—“Risk Factors,” for further information.

Capital Requirements

The following table presents actual capital expenditures and debt maturities for 2021 and projected capital expenditures and future debt maturities for 2022 through 2026 (in millions, excluding AFUDC):

[[GREPCENT_TABLE]]
[["","Years Ending December 31,"],["","2021","","2022","","2023","","2024","","2025","","2026"],["Ongoing capital expenditures (1)","$","620","","","$","625","","","$","650","","","$","650","","","$","650","","","$","650"],["Integrated Operations Center","60","","","35","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Total capital expenditures (2)","$","680","","","$","660","","","$","650","","","$","650","","","$","650","","","$","650"],["Long-term debt maturities","$","160","","","$","\u2014","","","$","\u2014","","","$","80","","","$","\u2014","","","$","\u2014"]]
[[/GREPCENT_TABLE]]

(1) Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects. Includes accrued capital additions, preliminary engineering, removal costs, and certain intangible working capital assets.

(2) Amounts subsequent to 2021 are estimates as of the date of this report and may be affected by economic conditions, including but not limited to, impacts of inflation, changes to the cost of materials and labor, and financing costs.

During 2021, PGE funded its capital expenditures through a combination of cash from operations in the amount of $532 million, and net proceeds from the issuance of FMBs in the total amount of $400 million. Capital expenditures in 2022 are expected to be $660 million. PGE plans to fund the 2022 capital expenditures with cash from operations during 2022, which is expected to range from $575 million to $625 million, the issuance of debt securities of up to $250 million, and the issuance of commercial paper, as needed. The actual timing and amount of any other issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Liquidity

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

59

Table of Contents

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

[[GREPCENT_TABLE]]
[["","Years Ended December 31,"],["","2021","","2020"],["Cash and cash equivalents, beginning of year","$","257","","","$","30"],["Net cash provided by (used in):"],["Operating activities","532","","","567"],["Investing activities","(656)","","","(787)"],["Financing activities","(81)","","","447"],["Net change in cash and cash equivalents","(205)","","","227"],["Cash and cash equivalents, end of year","$","52","","","$","257"]]
[[/GREPCENT_TABLE]]

2021 Compared to 2020

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 2021 compared to 2020 (dollars in millions):

[[GREPCENT_TABLE]]
[["","Increase/ (Decrease)"],["Increase in Net income due primarily to energy trading losses in 2020","$","89"],["Decrease in Depreciation and amortization due to retirements and ARO revisions in 2020","(50)"],["Increase related to Deferred income taxes","28"],["Change in Decoupling mechanism deferrals, net of amortization","23"],["Amortization of Tax Reform refunds in 2020 and not in 2021","23"],["Decrease related to Deferral of incremental storm costs","(67)"],["Decrease related to Deferral of incremental wildfire costs","(15)"],["Decrease as a result of changes in Accounts receivable and Unbilled revenue","(40)"],["Increase for Accounts payable primarily due to the timing of payments to vendors","35"],["Increase as a result of net Margin activity","21"],["Decrease due to changes in Other working capital","(38)"],["Other miscellaneous changes","(44)"],["Net change in cash flow from operations","$","(35)"]]
[[/GREPCENT_TABLE]]

For additional information regarding changes in Net income, see the Results of Operations section in this Item 7.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 2022 will range from $420 million to $440 million. Combined with all other sources, cash provided by operations in 2022 is estimated to range from $575 million to $625 million.

Cash provided by operations includes the recovery in customer prices of cash charges related to various long-term contractual obligations such as interest on long-term debt and purchased power and fuel contracts. PGE’s anticipated employer contributions for its defined benefit pension plan and other postretirement plans is $3 million per year for the years ending 2022 through 2026. Contributions are expected to be covered by cash provided by operations. For additional information regarding contractual obligations, see Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

60

Table of Contents

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. The $131 million decrease in net cash used in investing activities in 2021 compared with 2020 is primarily 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.

The Company plans for $660 million of capital expenditures in 2022 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. PGE plans to fund the 2022 capital expenditures with cash from operations during 2022, as discussed above, as well as with the issuance of long-term debt securities, and short-term debt as necessary. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2021, cash provided by financing activities consisted primarily of the issuance of $400 million of FMBs. In addition, the Company issued a $200 million short-term loan, made payments on short-term debt in the amount of $350 million, paid dividends in the amount of $150 million, and executed a $12 million common stock repurchase.

2020 Compared to 2019

For a comparison of liquidity and capital resources and the Company’s cash flow activities for the fiscal year ended December 31, 2020 and 2019, see Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 19, 2021.

Credit Ratings and Debt Covenants

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

[[GREPCENT_TABLE]]
[["","Moody\u2019s","","S&P"],["First Mortgage Bonds","A1","","A"],["Senior unsecured debt","A3","","BBB+"],["Commercial paper","P-2","","A-2"],["Outlook","Stable","","Stable"]]
[[/GREPCENT_TABLE]]

In the event Moody’s and/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, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE’s consolidated balance sheets, while any letters of credit issued are not reflected in the Company’s consolidated balance sheets.

As of December 31, 2021, PGE had posted $55 million of collateral with these counterparties, consisting of $37 million in cash and $18 million in bank letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2021, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $62 million and decreases to $36 million by December 31, 2022. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $129 million and decreases to $101 million by December 31, 2022 and $80 million by December 31, 2023.

61

Table of Contents

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 securing the bonds. PGE estimates that on December 31, 2021, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $799 million 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 of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facilities contain 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 December 31, 2021, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 55.9%.

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.

Short-term Debt—Pursuant to an order issued by the FERC on January 20, 2022, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2024. The following table shows available liquidity as of December 31, 2021 (in millions):

[[GREPCENT_TABLE]]
[["","December 31, 2021"],["","Capacity","","Outstanding","","Available"],["Revolving credit facility (1)","$","650","","","$","\u2014","","","$","650"],["Letters of credit (2)","220","","","79","","","141"],["Total credit","$","870","","","$","79","","","$","791"],["Cash and cash equivalents","","","","","76"],["Total liquidity","","","","","$","867"]]
[[/GREPCENT_TABLE]]

(1)Scheduled to expire September 2026.

(2)PGE has three 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 December 31, 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 as black, indigenous, and people of color. Pursuant to the terms of the agreement, the revolving credit facility may be used as

62

Table of Contents

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, 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 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. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2021, PGE had no commercial paper outstanding.

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

Under the revolving credit facility, as of December 31, 2021, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2021, the aggregate unused available credit capacity under the revolving credit facility was $650 million.

In addition, PGE has three letter of credit facilities under which the Company has total capacity of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, which are considered off-balance sheet arrangements, letters of credit for a total of $79 million were outstanding as of December 31, 2021.

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 FMB bond issuance.

Long-term Debt—During 2021, PGE issued a total of $400 million of FMBs, $150 million of which were issued under PGE’s Green Financing Framework, which allows the Company to issue bonds and other debt instruments to finance or refinance eligible green projects.

On September 30, 2021, PGE issued $400 million in FMBs. The Bonds consist of:

•a series, due in 2028, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 1.82%;

•a series, due in 2031, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 2.10%;

•a series, due in 2034, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 2.20%; and

•a series, due in 2051, in the amount of $150 million that will bear interest from its issuance date at an annual rate of 2.97%.

As of December 31, 2021, total long-term debt outstanding, net of $14 million of unamortized debt expense, was $3,285 million, none of which is scheduled to mature in 2022.

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 debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 45.2% and 45.0% as of December 31, 2021 and 2020, respectively.

Critical Accounting Policies and Estimates

63

Table of Contents

The preparation of consolidated financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain.

Regulatory Accounting

As a rate-regulated enterprise, PGE applies regulatory accounting, which includes the recognition of regulatory assets and liabilities on the Company’s consolidated balance sheets. Regulatory assets represent probable future revenue associated with certain incurred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited or refunded to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established or subject to approval by independent third-party regulators, prices are designed to recover the specific enterprise’s cost of service, and, in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Amortization of regulatory assets and liabilities is reflected in the statement of income over the period in which they are included in customer prices.

If future recovery of regulatory assets is not probable, PGE would expense such items in the period such determination is made. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting. Discontinued application of regulatory accounting would have a material impact on the Company’s results of operations and financial position.

For additional information on PGE’s regulatory assets and liabilities, see “Regulatory Matters” in the Overview section in this Item 7., and Note 7, Regulatory Assets and Liabilities in Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Asset Retirement Obligations

PGE recognizes AROs for legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Estimates for ARO liabilities are generally based on site-specific studies and are periodically subject to updates and changes that may arise over time.

Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions to ARO liabilities in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Accretion of the ARO liability is classified as Depreciation and amortization expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets.

64

Table of Contents

As a co-owner of Colstrip, PGE has provided surety bonds, which are considered off-balance sheet arrangements, of $23 million as of December 31, 2021 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC.

For additional information on AROs, see Note 8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”

Contingencies

PGE has various unresolved legal and regulatory matters about which there is inherent uncertainty, with the ultimate outcome contingent upon several factors. Such contingencies are evaluated using the best information available. A loss contingency is accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency and the reasons to the effect that it cannot be reasonably estimated are disclosed. Material loss contingencies are disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred. Established accruals reflect management’s assessment of inherent risks, credit worthiness, and complexities involved in the process. There can be no assurance as to the ultimate outcome of any particular contingency.

For additional information contingencies, see Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”