# PORTLAND GENERAL ELECTRIC CO /OR/ (POR) FY 2022 MD&A Verbatim Item 7 Management's Discussion and Analysis from PORTLAND GENERAL ELECTRIC CO /OR/'s 10-K for fiscal year 2022. SEC filing source: https://www.sec.gov/Archives/edgar/data/784977/000078497723000005/por-20221231.htm Accession: 0000784977-23-000005 Filing date: 2023-02-16 Report date: 2022-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/POR/ All MD&A years: /company/POR/mda/ Previous year: /company/POR/mda/fy2021/ (FY 2021) Next year: /company/POR/mda/fy2023/ (FY 2023) 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. 34 Table of Contents 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, the OPUC, the SEC, and the Division of Enforcement of the Commodity Futures Trading Commission (CFTC) with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs, and capital investments, energy trading activities, 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 the adoption of community choice aggregation; •the timing or 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 severe 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; •default or nonperformance on the part of any parties from whom PGE purchases capacity or energy, which may cause the Company to incur costs to purchase replacement power and related renewable attributes 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 or within budget, failure of counterparties to perform under agreements, or the abandonment of capital 35 Table of Contents projects, any of which could result in the Company’s inability to recover project costs, or impact PGE’s competitive position, market share, or results of operations in a material way; •volatility in wholesale power and natural gas prices, including but not limited to volatility caused by macroeconomic and international issues, 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, volatility of equity markets 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, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees; •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 attacks and 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, the ability to recruit and retain key employees and other talent, 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; •failure to achieve the Company’s greenhouse gas emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively respond to legislative requirements concerning greenhouse gas emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation; •political and economic conditions; •the impact of widespread health developments, including the global 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; 36 Table of Contents •risks and uncertainties related to 2021 All-Source RFP final shortlist projects, including, but not limited to regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including application of tariffs impacting solar module imports), and legislative uncertainty; 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. The Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. 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 Power—Reduce greenhouse gas emissions associated with electricity served to retail customers by at least 80% by 2030 and 100% by 2040; •Electrify the Economy—Increase beneficial electricity use to capture the benefits of new technologies while building an increasingly clean, flexible and reliable grid; and •Advance our Performance—Improve efficiency, safety, and system and equipment reliability while maintaining affordable energy service and growing earnings per share 5% to 7% annually. Climate Change State-mandated GHG emissions 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 emissions reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 37 Table of Contents 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the Laws and Regulations section of this Overview. Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 234 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 have similar goals and continue to consider similar goals for the future. The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows large business and municipality customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions. As of December 31, 2022, the Green Future Impact Program has an approved capacity of 750 MW nameplate. Through this voluntary program, the Company seeks to support the customers’ clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power. The Climate Pledge—In 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. Severe weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. Beginning December 27, 2022, strong, sustained winds and heavy precipitation caused approximately 180,000 power outages across PGE’s service territory. PGE incurred approximately $5 million in operating expenses related to the storm, of which $4 million has been deferred under PGE’s major storm damage recovery mechanism. On September 9 and 10, 2022, extreme fire conditions and hot, strong wind gusts led PGE to implement a proactive Public Safety Power Shutoff (PSPS) in ten identified PSPS areas and seven additional preventive outage areas. The PSPS event impacted approximately 37,000 customer homes and businesses. Power was restored to all customers impacted by the PSPS on September 11, 2022. PGE incurred approximately $1 million in costs in preparation activities leading up to the event, which have been deferred under the wildfire mitigation deferral mechanism (see “Wildfire mitigation” in the “Regulatory Matters” section of this Overview for more information on the impact to PGE’s results of operations). In June 2021, temperatures in the region reached all-time recorded highs, shattering the Company’s previous summer peak load demand reached in August 2017 and all time peak load established in December 1998. In 2021, Oregon also experienced an extreme wildfire season, following the 2020 destructive wildfire season, and a severe ice storm. The ice storm led to historic levels of customer power outages, and caused considerable expense for service restoration and damage repair (see “February 2021 ice storms and damage” in 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. 38 Table of Contents Investing in a Clean Energy Future 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. In 2020, the OPUC acknowledged, subject to conditions and directives, the Company’s 2019 IRP and associated Action Plan. With the passage of HB 2021, PGE is preparing a Clean Energy Plan (CEP), which will articulate the Company’s strategy to meet the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and is required to be filed in connection with, the Company’s IRP. In 2021, PGE filed an extension waiver for the next IRP, which the OPUC approved. PGE anticipates filing its first combined IRP and CEP with the OPUC on March 31, 2023. That filing will project PGE’s resource and capacity needs over the next 20 years and propose an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements. PGE estimates a need of approximately 3,000 to 4,000 MW in order to meet the Company’s 2030 emissions reduction target. PGE estimates that this need will be met by targeted acquisition of approximately 2,000 to 3,000 MW of non-emitting resources and adding approximately 1,000 MW of non-emitting dispatchable capacity through new acquisition or extending existing capacity contracts. The Company is in the process of evaluating and updating these projections in anticipation of the upcoming IRP and CEP filing. 2021 All- Source RFP In 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, to fill the need identified in the 2019 IRP action plan and to meet a portion of the Company’s estimated 2030 need. PGE issued the final 2021 All-Source RFP in December 2021, and proposals were submitted in January 2022. PGE submitted a request for acknowledgement of the final shortlist to the OPUC on May 5, 2022 that included seven distinct projects submitted by five bidders for renewable resources and six distinct projects by four bidders for capacity resources. On July 14, 2022, during a public meeting, the OPUC acknowledged, with conditions, PGE’s proposed final shortlist of renewable resources and non-emitting dispatchable capacity. Subsequently, on August 31, 2022, the OPUC issued its order, memorializing its July 14, 2022 acknowledgement, with conditions. Following the passage of the Inflation Reduction Act, PGE provided an opportunity for all bidders selected to the final shortlist to refresh their pricing. Updated pricing was received in August 2022 and PGE, in collaboration with an Independent Evaluator, updated scoring and ranking to reflect pricing changes from bidders. An updated Independent Evaluator's report was filed as an informational update to the OPUC on September 30, 2022. Pursuant to the 2021 All-Source RFP process, PGE has entered into agreements to acquire the following: •Clearwater Wind Development—PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. entered into agreements to construct a 311 MW wind energy facility, which will be part of the larger Clearwater Wind development in Eastern Montana. PGE will own 208 MW of production capacity of the 311 MW in these agreements, with an investment of approximately $415 million, excluding an allowance for funds used during construction (AFUDC). Subsidiaries of NextEra Energy Resources, LLC will own the remaining 103 MW of production capacity and will sell their portion of the output to PGE under a 30-year PPA. Subsidiaries of NextEra Energy Resources, LLC plan to design, build, and operate the facility. The agreements signed by PGE and subsidiaries of NextEra Energy Resources, LLC will be subject to prudency review on customers’ behalf by the OPUC. The project has an estimated commercial operation date of December 31, 2023. PGE continues to negotiate with remaining bidders on the final shortlist, with expectations to finalize negotiations in the first half of 2023. PGE filed a status report on December 1, 2022 with the OPUC on the current status of negotiations to meet the remaining 2021 All Source RFP targets, including: •Approximately 75 to 200 MW of renewable resources; 39 Table of Contents •Approximately 375 MW of non-emitting dispatchable capacity resources that can be used to meet peak customer demand; and •One or more resources for the Company’s Green Future Impact Program. Under the Green Future Impact Program, PGE plans to acquire up to 100 MW of new wind, solar, or hybrid renewable and battery storage resources to meet subscriber demand under the PGE supply option. The Company expects the Green Future Impact Program resources considered in the 2021 All-Source RFP to be incremental to the 150 MWa renewable energy target envisioned under the 2019 IRP Action Plan. Renewable resources in PGE’s 2021 All-Source RFP must be eligible under Oregon’s RPS and qualify for the federal production tax credit (PTC) or the federal investment tax credit. All resources (dispatchable capacity or renewable) must be online by the end of 2024, with certain exceptions for long-lead time resources. In February 2022, NewSun Energy LLC (NewSun) filed a petition for judicial review in the Marion County Circuit Court against the OPUC, challenging the scoring methodology in the 2021 All-Source RFP. PGE joined in the case as an intervenor. NewSun also filed a motion to stay the 2021 All-Source RFP process, which the Court subsequently denied. The OPUC filed a motion to dismiss the case and PGE joined the OPUC’s motion to dismiss. NewSun opposed the motion. In May 2022, the Court granted the motion to dismiss to which NewSun responded in June 2022 by filing a notice of appeal with the Court of Appeals of the State of Oregon. NewSun has requested multiple extensions to file opening briefs in the appeal. On October 28, 2022, NewSun filed a petition in Deschutes County Circuit Court seeking review of the OPUC order acknowledging, with conditions, PGE’s 2021 All-Source RFP shortlist. PGE cannot predict the outcome of these proceedings or potential impact, if any, to its ongoing 2021 All-Source RFP process. 2023 All-Source RFP PGE filed notice with the OPUC on January 31, 2023 that an RFP in 2023 is needed to procure resources to meet a forecasted 2026 capacity shortfall and to make continued progress toward HB 2021’s decarbonization targets. These actions are consistent with the forthcoming 2023 IRP Action Plan and CEP. The filing includes PGE’s request for a waiver of the OPUC’s competitive bidding rules and outlines PGE’s recommended timeline for obtaining necessary regulatory approvals and issuing the RFP to the market in the third quarter of 2023. PGE desires to select a final shortlist and submit a request for acknowledgment to the OPUC in December of 2023. Building a resilient grid—To serve communities with clean energy, PGE’s grid of the future will need to be smart and adaptive. Highlights of PGE’s key investments and plans for building a resilient grid include: •Wildfire Mitigation—PGE’s Wildfire Mitigation & Resiliency organization plans and implements the Wildfire Mitigation Program, developing and coordinating activities across the company. Under the 2022 Wildfire Mitigation Plan, PGE completed approximately $15 million in capital projects that include installing weather stations and wildfire-detection cameras as well as further hardening the electricity grid in high risk fire areas. PGE expects 2023 capital project spend will be materially consistent with 2022. •Virtual Power Plant (VPP)—PGE’s customer offerings related to energy efficiency programs, rooftop solar, battery storage and electric vehicle chargers aim to support grid reliability and increase portfolio flexibility and resource diversity. These distributed energy resources are the foundation of PGE’s VPP that will provide a growing suite of grid and system services over time. When coordinated through a VPP platform, distributed energy resources and flexible loads can help the Company achieve cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enable PGE’s distribution system plan (DSP) vision of a dynamic two-way system. In 2022, PGE successfully used batteries in the VPP to contribute to 40 Table of Contents system needs and improve grid reliability, demonstrating that, as distributed energy resources scale, PGE has the technology to use them to support resource adequacy and decarbonization goals. •Distribution System Plan—In 2021, PGE filed its inaugural DSP, 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, EV charging, and solar panels where communities—especially underserved Oregonians—need them. The plan consists of two parts, the first of which was acknowledged by the OPUC on March 8, 2022. Part Two was filed on August 15, 2022. Electrify the economy—To help Oregon reach its decarbonization goals, PGE is working to build a safe, reliable, and affordable, economy-wide, clean energy future. The Company is committed to increase electrification of buildings and support the accelerating pace of vehicle electrification for our customers, as well as our own vehicle fleet. In 2022, PGE completed approximately $11 million in capital projects related to electrifying PGE’s vehicle fleet. Transportation electrification is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to develop infrastructure projects aimed at improving accessibility to electric vehicle charging stations, build fleet partnerships, and offer programs to encourage customers to advance transportation electrification. In 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 Oregon’s GHG emissions reduction goals. In 2020, the OPUC accepted the plan and related costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. In 2021, the Oregon legislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification. PGE made a request to the OPUC to delay the filing of its next full Transportation Electrification plan until no later than June 1, 2023 to allow for time for review and evaluation of the plan in the context of the Company’s IRP and CEP filings. This request was approved by the OPUC on February 7, 2023. Businesses and families continue to turn to electricity to serve their home and workplace needs and PGE continues to share information on the benefits of electric appliances, landscaping tools and equipment, and heat pumps, which provide efficient heating and cooling. In addition, the Company continues to pursue advanced technologies to enhance the grid, pursue distributed generation and energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs. Laws and Regulations Infrastructure Investment and Jobs Act—On November 15, 2021, President Biden signed into law the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA), which includes approximately $550 billion of new federal spending. PGE is pursuing multiple areas under the IIJA for potential grant funding of projects. These projects target improvements in electrical system reliability and resiliency, wildfire situational awareness and mitigation, greater communications capabilities, advancements in customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, and regional transmission capacity constraints. As of 2022, PGE has submitted two full applications. PGE cannot predict the ultimate timing and success of securing funding from programs under the IIJA. Inflation Reduction Act of 2022—The Inflation Reduction Act of 2022 (IRA) was signed into law by President Biden on August 16, 2022 with a majority of the provisions effective for tax years beginning after December 31, 2022. Among other provisions, the bill includes: •implementation of a new corporate alternative minimum tax (CAMT) for applicable corporations with average adjusted financial statement income over a three-year period in excess of $1 billion per year; 41 Table of Contents •an excise tax of 1% of the fair market value of any stock which is repurchased, reduced by any stock issued during the taxable year; and •significant tax incentives for energy and climate initiatives, including: ◦A three-year extension and modification of PTCs for facilities that begin construction before December 31, 2024; ◦The ability to transfer or sell PTCs to other taxpayers; ◦Reestablished solar PTC which would allow PGE the opportunity to be competitive in owning solar resources in renewable RFPs; ◦An opt-out of Investment Tax Credit (ITC) normalization requirements on certain stand-alone storage projects; ◦Beginning January 1, 2025, the traditional resource-specific PTCs and ITCs are replaced with technology-neutral clean electricity credits. Critical normalization alternatives are retained with these credits; and ◦Several provisions supporting expanded transportation electrification. The Company does not expect the excise tax on stock repurchases and the new CAMT to have an impact on the Company’s results of operations. PGE will be closely monitoring guidance from the IRS regarding the enhanced energy credits available under the IRA. Compared to previous resource planning processes, the Company believes the new tax incentives will provide additional investment opportunities for PGE and result in lower customer prices. Increased capital expenditures in such investment would likely result in additional financing needs through debt and equity instruments. HB 2021—In June 2021, the Oregon Legislature passed HB 2021, which requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. The baseline levels for PGE are the average annual emissions for the years 2010, 2011, and 2012 associated with the electricity sold to its retail electricity consumers as reported to the Oregon Department of Environmental Quality (ODEQ). HB 2021 requires utilities to develop a CEP for meeting the targets, concurrent with each IRP, and to develop a DSP at reasonable costs to retail electricity consumers. In reviewing a CEP, the OPUC must ensure that utilities plan for equitable implementation and demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions. Regulated entities will continue to report annual GHG emissions to the ODEQ, as they do today. In threshold years, and every year thereafter, the OPUC will use the data reported to the ODEQ for that compliance year to determine whether the reduction targets are met. The preliminary percentage of 2022 retail load served by non-emitting resources is 39 percent. This amount excludes generation and purchases associated with power delivered outside of PGE service territory and is calculated utilizing methodology per the ODEQ’s Greenhouse Gas Reporting Protocol for investor-owned utilities. The underlying information is subject to ODEQ review and approval. HB 2021 also: •Aligns with PGE decarbonization goals; •Establishes clear decarbonization authority for the OPUC, including authority over ESSs; •Modernizes competition provisions of Oregon’s electricity restructuring law from 1999; •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. 42 Table of Contents Governor executive orders—In 2020, the Governor of Oregon issued an executive order that directed State agencies to integrate climate change and the State’s GHG emissions reduction goals into their plans, budgets, investments, and decisions to the extent allowed by law. Among other things, the executive order directed the OPUC to: •encourage electric companies to support transportation electrification infrastructure that supports GHG emissions reductions and zero-emission vehicle goals; •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; and •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. In addition, the executive order directed the ODEQ to adopt a program to cap and reduce GHG emissions within the State from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. In December 2021, the ODEQ adopted the Climate Protection Plan, which provided an exemption for electricity generation from the Company’s natural gas-fired resources. The executive order also modified 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 by 2025, to a 25 percent reduction by 2035. PGE continues to monitor activities of State agencies that have utilized the executive order to shape State policy or seek to implement the order through their own regulatory authority. 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. PGE ceased coal fired operation at its Boardman generating facility in 2020 and continues the process of decommissioning the plant. The Company has a 20% ownership share in Colstrip Units 3 and 4 and in response to SB 1547, the Company filed a tariff request in 2016 with the OPUC and received approval to accelerate recovery of PGE’s investment in Colstrip from 2042 to 2030. In 2020, the owners of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has no direct ownership interest in those units, ongoing operations of Units 3 and 4 utilize certain common facilities with Units 1 and 2. Effective May 9, 2022, PGE’s depreciation rates and associated customer prices changed as approved by the OPUC in the Company’s 2022 General Rate Case (2022 GRC) to reflect further accelerated depreciation of Colstrip Units 3 and 4 from 2030 to December 31, 2025. In order to meet PGE’s regulatory and legislative requirements, the Company continues to evaluate the possibility of exiting ownership of Units 3 and 4 to meet PGE’s regulatory and legislative requirements. 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 an approximate 15% ownership interest in, and capacity on, the Colstrip transmission facilities. See “Investing in a Clean Energy Future” in this Overview for information regarding development in eastern Montana. Other provisions of SB 1547 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 43 Table of Contents for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and •An opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s RAC filings. 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 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 Cases—In July 2021, PGE filed with the OPUC a GRC based on a 2022 test year. Following a public review process, on April 25, 2022, the OPUC issued Order 22-129, which authorized a: •capital structure of 50% debt and 50% equity; •return on equity of 9.5%; and •cost of capital of 6.813%. Order 22-129 resolved the annual revenue requirement reflecting an increase of $74 million and an average rate base of $5.6 billion. New customer prices, as approved by the OPUC, became effective May 9, 2022. Key elements of the OPUC’s Order also: •established a balancing account for the Company’s major storm damage recovery mechanism; •denied PGE’s proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project. The Company had requested that recovery of the capital cost of improvements at the Faraday hydroelectric facility be included in the new rate base. However, as the project was not yet placed in-service, the capital-related revenue requirement was removed and PGE was allowed to pursue recovery in the Company’s next GRC. As of December 31, 2022, the construction work-in-progress balance associated with Faraday was $168 million, including AFUDC; •required PGE to defer and refund, subject to an earnings test, the revenue requirement associated with Boardman included in customer prices following plant closure in 2020 (for more information see “Deferral of Boardman revenue requirement” within this “Overview” section); and •created an earnings test for the deferrals for the 2020 Labor Day wildfire and the February 2021 ice storm and damage to be applied on a year-by-year basis. Further, the parties agreed to eliminate PGE’s decoupling mechanism, which provided 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 when customer prices were set. From May 9 through the remainder of 2022, estimated collections from, or refunds to, customers were pro-rated and are expected to be amortized into customer prices in 2024 over a one-year period. For further information on the decoupling mechanism, see “Decoupling” in this Overview section. As a result of the earnings tests outlined in the OPUC’s Order, the Company released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for 2022 in the amount of $17 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. For the years 2021 and 2022, PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no further release of deferrals or earnings test reserve is expected. The OPUC has significant discretion in making the final determination of the application of the earnings 44 Table of Contents test for 2020, 2021, and 2022 and the final determination could result in additional disallowances or refunds, which could be material, compared to the amount reserved by the Company as of December 31, 2022. On February 15, 2023, PGE filed with the OPUC a GRC based on a 2024 test year (2024 GRC) requesting an increase that, when including Colstrip-related adjustments through a supplemental tariff, results in an overall average increase of approximately 14.0% in customer prices for 2024. The requested price increase includes an approximate 4.5% increase as a result of higher NVPC expected in 2024. The NVPC projection will be updated periodically during 2023. The Company’s 2024 GRC filing seeks recovery of capital investments made across the business to meet growing demand, improve reliability, resiliency, and capability to deliver safe, reliable, clean electricity to customers. A significant portion of the Company’s capital is related to the continued investment in the transmission and distribution system to meet evolving customer expectations and growing demand while also replacing aging infrastructure. PGE’s request also includes recovery of the capital costs to repower the original 1907 Faraday hydro facility, which was placed into service January 31, 2023. PGE is seeking operations and maintenance increases critical for maintaining the ability to deliver safe, reliable, affordable power amid a period of record inflation. The Company has seen cost pressures in various areas of the business, including labor, wholesale electricity and natural gas commodity prices, and the increased cost-of-debt associated with higher interest rates on its long-term debt. The Company is also proposing key changes to its PCAM and modifications to the AUT to better address highly dynamic and volatile power market uncertainties and evolving regional fundamental drivers. PGE has requested a: •capital structure of 50% debt and 50% equity; •return on equity of 9.8%; •cost of capital of 7.06%, which reflects updates for actual and forecasted debt costs; and •a rate base of $6.3 billion. Complete details of the 2022 GRC filing (OPUC Docket UE 394), the resulting OPUC Order, are available on the OPUC website at www.oregon.gov/puc. Regulatory review of the 2024 GRC (OPUC Docket UE 416) will continue throughout 2023, with a final order expected to be issued by the OPUC in December 2023, for new customer prices effective January 1, 2024. COVID-19 impacts—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. 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 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. As of December 31, 2022 and December 31, 2021, PGE’s deferred balance was $22 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE did not defer incremental bad debt expense associated with customers who are not on a time payment arrangement in 2022. The Company released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for 2022 in the amount of $2 million. The amount recorded represents the Company’s estimate based on its understanding of the OPUC’s intent to apply an earnings test to certain elements of utility COVID deferrals. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. The request for amortization has an effective date of April 1, 2023, and is still pending the approval of the Commission. 45 Table of Contents Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test. PGE believes the amounts deferred are 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 and the application of an earnings review could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. 2020 Labor Day wildfire—In 2020, Oregon experienced the most destructive wildfire season 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. In October 2020, the OPUC formally approved PGE’s request for deferral of 2020 wildfire-related costs. As of December 31, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the 2020 wildfire response was $31 million and $45 million, respectively. Pursuant to the earnings tests outlined in Order 22-129, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for 2022 in the amount of $15 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect the deferred costs in customer prices over a seven-year amortization period beginning November 1, 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and would allow PGE full recovery of the amounts deferred as of September 30, 2022, with amortization over a seven-year period. Order 22-435, issued November 3, 2022, adopted the stipulation approving amortization of amounts that began on January 1, 2023. Wildfire mitigation—Represents incremental costs and investments made by PGE related to intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises under SB 762, which was passed in the 2021 legislative session with an effective date of July 19, 2021. 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 SB 762, PGE submitted a risk-based wildfire protection plan to the OPUC in December 2022. In Order 22-129, the OPUC did not adopt any rate adjustment mechanisms, but rather invited PGE to submit a filing proposing a cost recovery mechanism for incremental wildfire costs consistent with SB 762 and establishing an ongoing review for reasonableness. The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in customer prices in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in customer prices. As of December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $28 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence, 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. PGE submitted a tariff filing on August 19, 2022 for an automatic adjustment clause for incremental wildfire mitigation spending, as allowed under SB 762. The filing included a proposal to report semi-annually to show PGE’s progress relative to its Wildfire Mitigation Plan, which is filed under docket UM 2208. On September 9, 2022, the OPUC suspended the tariff and opened docket UE 412 to investigate the filing. On January 13, 2023, PGE, Staff, and certain intervenors have entered into a partial stipulation that would establish a Wildfire Mitigation Mechanism that would allow recovery of PGE’s prudently incurred wildfire mitigation costs, subject to a prudency review. The partial stipulation also supports the deferral of PGE’s wildfire mitigation costs related to 2022 and 2023 46 Table of Contents that exceed the amount currently granted in customer prices, subject to a prudency review. The partial stipulation is pending OPUC approval which is targeted for May 10, 2023. The Company’s deferral application for expenses related to wildfire mitigation, filed in 2019 under OPUC Docket UM 2019, has not yet been approved by the OPUC. February 2021 ice storms and damage—In February 2021, a historic set of storms involving heavy snow, winds and ice impacted the United States, including PGE’s service territory. 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. 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, 2022, the Company has deferred a total of $74 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 received OPUC Order No. 22-020 approving the February storms deferral on January 26, 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and would allow PGE full recovery of the deferred amounts with amortization over a seven-year period. The OPUC adopted the stipulation approving amortization of amounts with amortization that began on January 1, 2023. Declared states of emergency—In September 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 apply deferred accounting treatment for 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, 2022, 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 2022 AUT included a final increase in power costs for 2022, and a corresponding increase in annual revenue requirement, of $64 million from 2021 levels, which were reflected in customer prices effective January 1, 2022. The 2023 AUT contains a $186 million increase in NVPC that will be recovered in customer prices beginning January 1, 2023. See “Power operations” within this Overview section of Item 7 for more information regarding the PCAM. For 2021, actual NVPC was $62 million above baseline NVPC, which was outside the established deadband range. Therefore, PGE deferred $29 million, which represents 90% of the excess variance expected to be collected from customers for the year ended December 31, 2021. In conjunction with the OPUC’s annual review of the Company’s PCAM filing, on October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to this deferral and would allow PGE full recovery of deferred costs, except for $2 million. The OPUC issued an order November 8, 2022 approving the stipulation. Amortization over a two-year period began January 1, 2023. See “Power operations” within this Overview section of Item 7 for more information regarding the PCAM. 47 Table of Contents Portland Harbor Environmental Remediation Account (PHERA) mechanism—The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of December 31, 2022, 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 (ROD) 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 were to be 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, previously authorized by the OPUC through 2022, was 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 provided for collection from (or refund to) customers if weather-adjusted use per customer was less (or more) than that projected in the Company’s most recent GRC. Collections under the decoupling mechanism were 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 estimated collections recorded in 2022, the Company did not reach the 2% limit for any applicable tariff schedule that would be applied when actually collected in 2024. No limit existed for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic resulted in larger estimated refunds under the decoupling mechanism, which largely offset the revenue increases that resulted from higher residential demand. In the 2022 GRC, parties reached an agreement that has eliminated PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to the case, which began May 9, 2022. Pursuant to the GRC Order, the OPUC adopted the agreement such that deferrals will not occur after 2022, although amortization of then previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices and deferral continued through the end of 2022 on a prorated basis. In the 2024 GRC filing, the Company has included a concept proposal that could lead to resuming decoupling January 1, 2024, with certain modifications. For the year ended December 31, 2022, the Company recorded an estimated refund of $3 million to residential customers and a collection of $6 million from commercial customers that resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company saw a decline in weather-adjusted use per customer from both residential and commercial customers during 2022 compared to 2021 levels, although residential usage continued to exceed the projections. 48 Table of Contents At December 31, 2021, PGE had recorded a total refund of $10 million that will be refunded to customers over a one-year period, which began January 1, 2023. 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 the Company’s Boardman coal-fired generating plant (Boardman) then included in customer prices as established in the Company’s 2019 GRC. The application stated a deferral was required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. PGE estimated the revenue requirement for Boardman to be $14 million for the year ended December 31, 2020, an additional $66 million for the year ended December 31, 2021, and $23 million for the year ended December 31, 2022. In the 2022 GRC Order, the OPUC found that the deferral was warranted with amortization subject to an earnings test. On July 27, 2022, the Company filed an application, which, subject to OPUC approval, showed that the Company did not exceed the earnings test threshold for 2020 or 2021 and consequently, no refund would be required for those years. Customer prices resulting from the 2022 GRC Order no longer include any revenue requirement related to Boardman after new customer prices took effect on May 9, 2022. Although still subject to OPUC review, PGE does not believe it exceeded its regulated return on equity under the earnings test for 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and states that no refund is necessary for that year. The stipulation remains subject to OPUC approval. Review and determination of potential refund for the periods related to 2020 and 2022 remain outstanding. In November 2022, the OPUC granted a motion by PGE to suspend the procedural schedule and directed the Company to file a status update no later than February 16, 2023. In granting the ruling the OPUC noted that it expects to resolve this matter, addressing both the 2020 and 2022 deferrals within the first half of 2023. Based on the application of an earnings test, PGE has not recorded a refund related to Boardman for 2020, 2021, or 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022, and could require additional refunds that would be recognized as a charge to earnings, which could be material. 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 each year, outside of a GRC. There were no significant filings made under the RAC during 2022. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. PGE is requesting within its 2024 GRC that the OPUC clarify that energy storage used to integrate renewables on a utility’s system qualifies as associated energy storage. Operating Activities In addition to 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. PGE also performs portfolio management and wholesale market sales services for third parties in the region. The Company participates in the western EIM, which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. In its ongoing effort to benefit retail and wholesale customers, PGE has announced its intention to join the Western Power Pool and a binding resource adequacy program for the region known as the WRAP. Ten other utilities in the western United States and Canada have recently signaled similar intent. The WRAP represents an effort to increase reliability and clean energy in the region through resource diversification and load sharing while managing overall costs. The Company also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market. 49 Table of Contents PGE 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 and did record a new winter peak load in December 2022. Summer peak deliveries have continued to exceed those of the winter months for several years, generally resulting from air conditioning demand and the trend toward a warmer overall climate. During the summer of 2021, demand reached a new all-time high, surpassing the previous mark, which was a winter peak. For further information regarding seasonal fluctuations, see “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” Retail customer price changes and customer usage patterns, which can be affected by the economy and recently, by changes resulting from COVID-19, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to help ensure the availability of supply chain-constrained items that are needed to serve new and existing customers, such as advance ordering of critical materials, pre-securing manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. PGE has also taken measures to help mitigate cost increases through long term agreements, supplier engagement and expanding the supply base. Customers and demand—The following tables present total energy deliveries and the average number of retail customers by customer type for 2022 and 2021. [[GREPCENT_TABLE]] [["Energy deliveries (MWh in thousands)","","","2022","","","","2021","","% Increase/ (Decrease)"],["Retail:"],["Residential","","","8,088","","","","","7,978","","","1.4","%"],["Commercial (PGE sales only)","","","6,650","","","","","6,604","","","0.7"],["Direct Access","","","548","","","","","589","","","(7.0)"],["Total Commercial","","","7,198","","","","","7,193","","","0.1"],["Industrial (PGE sales only)","","","4,167","","","","","3,714","","","12.2"],["Direct Access","","","1,778","","","","","1,647","","","8.0"],["Total Industrial","","","5,945","","","","","5,361","","","10.9"],["Total (PGE sales only)","","","18,905","","","","","18,296","","","3.3"],["Total Direct Access","","","2,326","","","","","2,236","","","4.0"],["Total retail energy deliveries","","","21,231","","","","","20,532","","","3.4","%"],["Wholesale energy deliveries","","","6,000","","","","","5,946","","","0.9"],["Total energy deliveries","","","27,231","","","","","26,478","","","2.8","%"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["Average number of retail customers","","2022","","2021","","% Increase/ (Decrease)"],["Residential","","809,573","","","88","%","","800,372","","","88","%","","1.1","%"],["Commercial","","112,127","","","12","","","111,062","","","12","","","1.0"],["Industrial","","192","","","\u2014","","","191","","","\u2014","","","0.5"],["Direct access","","552","","","\u2014","","","584","","","\u2014","","","(5.5)"],["Total","","922,444","","","100","%","","912,209","","","100","%","","1.1","%"]] [[/GREPCENT_TABLE]] In 2022, retail energy deliveries increased 3.4% from 2021, with increases reflected in all three customer categories, although driven by strong demand from industrial customers. The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Residential usage continues to be elevated compared to levels seen before COVID-19, as remote and hybrid work schedules remain in place across the Company’s service area. Weather had a positive impact on deliveries with warmer than normal 50 Table of Contents temperatures experienced during the summer months and overall cooler weather seen during the heating seasons than in 2021. 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. 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 remained. In 2022, PGE began to see decreases in average residential usage on a weather-adjusted, year over year basis, however we expect that the shift that has occurred with respect to hybrid work schedules will have lasting impacts on average usage. Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 1.4% higher in 2022 than 2021, due to a 0.2% increase in average usage per customer, which resulted largely from warmer summer and colder fourth quarter temperatures, and a 1.1% increase in the average number of customers. Commercial energy deliveries were fairly stable in 2022 with the prior year, showing an increase of 0.1%. While COVID-19 related recovery has largely occurred, continued impacts of programmatic energy efficiency and uncertainty in economic conditions have tempered commercial growth in 2022. Industrial energy deliveries increased 10.9% in 2022 due to continued strength in the high-tech manufacturing and digital service sector. Several large customers experienced continued growth in 2022 and new data center facilities came online. Total heating degree-days, an indication of electricity use for heating, in 2022 were fairly consistent overall with the 15-year average although 7% above total heating degree-days in 2021. The Company experienced a new record winter peak load in December 2022 of 4,113 MW. Total cooling degree-days, a similar indication of the extent to which customers were likely to have used electricity for cooling, in 2022, exceeded the 15-year average by 52%, although were only 3% above the 2021 total, illustrating that the two most recent summer seasons have been exceedingly warm compared to historical averages. The following table presents the number of heating and cooling degree-days in 2022 and 2021, along with the current 15-year averages, reflecting the influence that weather had on comparative energy deliveries. [[GREPCENT_TABLE]] [["","Heating Degree-Days","","Cooling Degree-Days"],["","2022","","2021","","15-Year Average","","2022","","2021","","15-Year Average"],["1st quarter","1,761","","","1,805","","","1,846","","","\u2014","","","\u2014","","","\u2014"],["2nd quarter","760","","","498","","","625","","","75","","","238","","","100"],["3rd quarter","6","","","54","","","72","","","745","","","600","","","467"],["4th quarter","1,576","","","1,471","","","1,560","","","45","","","\u2014","","","2"],["Total","4,103","","","3,828","","","4,103","","","865","","","838","","","569"],["Increase (decrease) from the 15-year average","\u2014","%","","(7)","%","","","","52","%","","47","%"]] [[/GREPCENT_TABLE]] On a weather-adjusted basis, total retail deliveries increased 2.0% from 2021. The increase was driven by a 10.6% growth in industrial deliveries, partially offset by a 0.5% decline in commercial energy deliveries and a 1.4% decrease in weather-adjusted deliveries to residential customers, as average use per customer has declined from the highs seen during the first two years of the COVID-19 pandemic. The Company projects that retail energy deliveries for 2023 will be between 2.5% and 3.0% above 2022 weather-adjusted levels, reflecting continued growth in industrial deliveries. 51 Table of Contents ESSs supplied Direct Access customers with energy representing 11% of PGE’s total retail energy deliveries during 2022 and 2021. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 12% of the Company’s total retail energy deliveries for 2022. With the adoption of the New Large Load Direct Access program in 2020, as much as 17% of the Company’s 2022 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"],["","2022","2021","","","2022","2021","","2022","2021"],["Thermal:"],["Natural gas","86","%","89","%","","","81","%","114","%","","41","%","48","%"],["Coal (3)","89","","81","","","","100","","103","","","11","","11"],["Wind (4)","82","","92","","","","81","","110","","","9","","12"],["Hydro","94","","83","","","","81","","73","","","5","","6"]] [[/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 reflects Colstrip, which PGE does not operate. (4)Plant availability includes Wheatridge, which PGE does not operate. Energy received from PGE-owned and jointly-owned thermal plants in 2022 compared to 2021 decreased by 8%. This decrease is primarily related to PGE’s natural gas-fired plants which were displaced by higher hydroelectric generation and purchases, and economic dispatch decisions in response to higher natural gas prices. 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 25% in 2022 compared to 2021 primarily due to increased runoff resulting from more favorable snowpack conditions. Energy received from mid-Columbia and other regional hydroelectric projects increased 31% while energy generated by the Company-owned facilities decreased 4% in 2022 largely as a result of PGE’s sale of 16.66% of its ownership interest in Pelton/Round Butte to the CTWS, effective January 1, 2022. PGE purchases 100% of the CTWS’s share of the project output. 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. 52 Table of Contents Energy received from PGE-owned wind resources and under contracts decreased 22% in 2022 compared to 2021 primarily due to unplanned plant outages during the period. 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. 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 2022 and 2021: •For 2022, actual NVPC was above baseline NVPC by $23 million, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2022. A final determination regarding the 2022 PCAM results will be made by the OPUC through a public filing and review in 2023. •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 deferred $30 million, which represented 90% of the excess variance expected to be collected from customers. On October 24, 2022, PGE and Parties submitted a stipulation with the OPUC that resolved all matters related to the 2021 PCAM and resulted in a deferred balance as of December 31, 2022 of $28 million, including interest. The OPUC issued Order 22-440 approving the stipulation and amortization began January 1, 2023 over a two-year period. See “Power costs” within “Regulatory Matters” in this Overview section of Item 7 for more information. The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $64 million increase was expected in 2022 over 2021. The 2023 AUT anticipates a $186 million increase in NVPC that will be recovered in customer prices beginning January 1, 2023. 53 Table of Contents Results of Operations The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations. The results of operations are as follows for the years presented (dollars in millions): [[GREPCENT_TABLE]] [["","Years Ended December 31,","","% Increase (Decrease)"],["","2022","","2021"],["","Amount","","Amount"],["Total revenues","$","2,647","","","$","2,396","","","10","%"],["Operating expenses:"],["Purchased power and fuel","988","","","822","","","20"],["Generation, transmission and distribution","348","","","310","","","12"],["Administrative and other","340","","","336","","","1"],["Depreciation and amortization","417","","","404","","","3"],["Taxes other than income taxes","157","","","146","","","8"],["Total operating expenses","2,250","","","2,018","","","11"],["Income from operations","397","","","378","","","5"],["Interest expense, net *","156","","","137","","","14"],["Other income:"],["Allowance for equity funds used during construction","14","","","17","","","(18)"],["Miscellaneous income, net","17","","","9","","","89"],["Other income, net","31","","","26","","","19"],["Income before income taxes","272","","","267","","","2"],["Income tax expense","39","","","23","","","70"],["Net income","$","233","","","$","244","","","(5)","%"]] [[/GREPCENT_TABLE]] * Includes an allowance for borrowed funds used during construction of $7 million in 2022 and $8 million in 2021. 2022 Compared to 2021 Net income for 2022 decreased $11 million from 2021 as the impact of higher natural gas and electricity prices coupled with increased customer demand drove Purchased power and fuel expense up. Increases in Retail revenues were led by the increase in customer prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT, although such increase fell considerably short of covering the incremental expense that the Company experienced, as well as higher customer demand. Retail energy deliveries increased 3.4% as energy deliveries to Industrial cost-of-service customers increased 12.2% in 2022 compared to 2021. Retail revenues were impacted by a slightly lower average price mix in 2022 as a result of the increased demand in the industrial sector. Wholesale revenues were the largest contributor to higher revenues in 2022 as wholesale power prices rose considerably along with marginally greater volumes. Increases in Operating expenses reflect the impact of the earnings tests outlined in OPUC Order 22-129, expenses related to service restoration costs, and continued vegetation management activities. Other income increased primarily due to a buyout of a retiree medical benefit plan in 2022, resulting in an $11 million settlement gain, partially offset by unfavorable market changes on the non-qualified benefit trust and lower AFUDC equity income on lower construction work-in-progress balances. Income taxes increased due primarily to higher Income before income tax expense combined with lower tax credits and a true up adjustment recorded in 2021 that reduced income tax expense. 54 Table of Contents Total revenues consist of the following for the years presented (in millions): [[GREPCENT_TABLE]] [["","2022","","2021","","% Increase (Decrease)"],["Retail: *"],["Residential","$","1,158","","","$","1,118","","","4","%"],["Commercial","723","","","690","","","5"],["Industrial","289","","","250","","","16"],["Direct Access","35","","","47","","","(26)"],["Subtotal","2,205","","","2,105","","","5"],["Alternative revenue programs, net of amortization","11","","","(29)","","","(138)"],["Other accrued revenues, net","7","","","2","","","250"],["Total retail revenues","2,223","","","2,078","","","7"],["Wholesale revenues","363","","","255","","","42"],["Other operating revenues","61","","","63","","","(3)"],["Total revenues","$","2,647","","","$","2,396","","","10","%"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["*","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 $12 million for 2022 and $18 million in 2021. Industrial revenues from ESS customers were $23 million and $29 million for 2022 and 2021, respectively."]] [[/GREPCENT_TABLE]] Total retail revenues—The following items contributed to the increase in Total retail revenues for the year ended December 31, 2022 compared to the year ended December 31, 2021 (dollars in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","2,078"],["Change as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)","69"],["Retail energy deliveries driven by higher industrial demand, increase in customers, and the effects of weather","66"],["Alternative revenue programs related to the decoupling mechanism due primarily to prorated elimination of the mechanism in 2022 and anticipated refunds recorded in 2021","13"],["Recovery in Revenues of storm related expenses","9"],["Combination of various supplemental tariffs and adjustments","(2)"],["Average price of energy deliveries due primarily to shift in mix among customer classes resulting from increased industrial demand","(10)"],["Year ended December 31, 2022","2,223"],["Change in Total retail revenues","$","145"]] [[/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 2022, a $108 million, or 42%, increase from 2021 in wholesale revenues resulted from a $106 million increase in average prices received when the Company sold power into the wholesale market. Although wholesale prices for electricity increased considerably during 2021 from the prior year, 2022 saw even higher prices. The higher sales prices in 2022 resulted from several factors including the overall economic recovery and macroeconomic factors impacting the energy commodity markets, although were driven largely by higher natural gas prices. In addition, sales volumes increased 1%, which contributed another $2 million. 55 Table of Contents Other operating revenues decreased $2 million, or 3%, in 2022 from 2021, primarily as a result of market conditions in 2021 that allowed the Company to sell excess natural gas in excess of amounts needed for the Company’s generation portfolio back into the wholesale market at gains that have exceeded those experienced during 2022. The gains were considerably higher in early 2021 due in part to the impact of unusual weather events on the demand for natural gas. Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. The following items contributed to the increase in Purchased power and fuel for the year ended December 31, 2022 compared to the year ended December 31, 2021 (dollars in millions, except for average variable power cost per MWh): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","822"],["Average variable power cost per MWh","13"],["Total system load","124"],["2021 PCAM deferral","29"],["Year ended December 31, 2022","988"],["Change in Purchased power and fuel","$","166"],["Average variable power cost per MWh:"],["Year ended December 31, 2021","$","33.63"],["Year ended December 31, 2022","$","37.71"],["Total system load (MWh in thousands):"],["Year ended December 31, 2021","25,295"],["Year ended December 31, 2022","26,215"]] [[/GREPCENT_TABLE]] For the year ended December 31, 2022, the $15 million increase related to the change in average variable power cost per MWh was primarily driven by a 5% increase in the average cost for purchased power, offset by a 13% decrease in the average cost of power from the Company’s own generation. The $124 million increase related to total system load was primarily due to a 23% increase in purchased power, driven largely by the economic displacement of gas facilities in 2022, offset by a 10% decrease in the company’s own generation. 56 Table of Contents PGE’s sources of energy, total system load, and retail load requirement for the years presented are as follows: [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2022","","2021"],["Sources of energy (MWh in thousands):"],["Generation:"],["Thermal:"],["Natural gas","8,242","","","31","%","","9,306","","","37","%"],["Coal","2,186","","","8","","","2,060","","","8"],["Total thermal","10,428","","","39","","","11,366","","","45"],["Hydro","1,027","","","4","","","1,073","","","4"],["Wind","1,765","","","7","","","2,316","","","9"],["Total generation","13,220","","","50","","","14,755","","","58"],["Purchased power:"],["Hydro","6,297","","","24","","","4,789","","","19"],["Wind","824","","","3","","","989","","","4"],["Solar","723","","","3","","","501","","","2"],["Natural Gas","33","","","\u2014","","","63","","","\u2014"],["Waste, Wood and Landfill Gas","168","","","1","","","167","","","1"],["Source not specified","4,961","","","19","","","4,031","","","16"],["Total purchased power","13,006","","","50","","","10,540","","","42"],["Total system load","26,226","","","100","%","","25,295","","","100","%"],["Less: wholesale sales","(6,000)","","","","","(5,946)"],["Retail load requirement","20,226","","","","","19,349"]] [[/GREPCENT_TABLE]] Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows: [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2022","","2021"],["Sources of energy (MWhs in thousands):"],["PURPA purchased power:"],["Hydro","36","","","15"],["Wind","25","","","30"],["Solar","588","","","472"],["Waste, Wood, Landfill Gas, and Other","101","","","102"],["Total","750","","","619"]] [[/GREPCENT_TABLE]] The following table presents the forecasted April-to-September 2023 and actual April-to-September 2022 and 2021 runoff at particular points of major rivers relevant to PGE’s hydro resources: [[GREPCENT_TABLE]] [["","Runoff as a Percent of Normal*"],["Location","2023 Forecast","","2022 Actual","","2021 Actual"],["Columbia River at The Dalles, Oregon","83","%","","107","%","","82","%"],["Mid-Columbia River at Grand Coulee, Washington","83","","","110","","","89"],["Clackamas River at Estacada, Oregon","90","","","139","","","70"],["Deschutes River at Moody, Oregon","78","","","92","","","84"]] [[/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. 57 Table of Contents Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $59 million in 2022 compared with 2021. The increase attributable to changes in Purchased power and fuel expense was the result of a 12% increase in the average variable power cost per MWh and a 4% increase in total system load. The increase in actual NVPC was also a result of the 41% higher average price per MWh sold and a 1% increase in the volume of wholesale energy deliveries. The following items contributed to the increase in Actual NVPC for the year ended December 31, 2022 compared to the year ended December 31, 2021 (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","567"],["Purchased power and fuel expense","138"],["Wholesale revenues","(108)"],["2021 PCAM Deferral","29"],["Year ended December 31, 2022","626"],["Change in NVPC","$","59"]] [[/GREPCENT_TABLE]] For further information regarding NVPC in relation to the PCAM, see “Power operations” in the Overview section of this Item 7. Generation, transmission, and distribution expense increased $38 million or 12% for the year ended December 31, 2022 compared to the year ended December 31, 2021, with the change attributed largely to the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","310"],["Release of previously deferred amounts pursuant to earnings test created in OPUC 2022 GRC Order","16"],["Higher service restoration and storm response costs","5"],["Higher distribution vegetation management, inspection, and maintenance expenses","4"],["Higher employee compensation and benefits expenses","4"],["Increase in generation facility maintenance expenses driven by major maintenance activities","3"],["Miscellaneous expenses","6"],["Year ended December 31, 2022","348"],["Change in Generation, transmission and distribution","$","38"]] [[/GREPCENT_TABLE]] For the year ended December 31, 2022, PGE deferred $27 million and $7 million in incremental wildfire mitigation costs and storm response costs, respectively. 58 Table of Contents Administrative and other expense increased $4 million or 1% for the year ended December 31, 2022 compared to the year ended December 31, 2021 due largely to the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","336"],["Regulatory program amortization","6"],["Higher facility maintenance, insurance, and licensing expenses","4"],["Higher bad debt expense","1"],["Lower professional service expenses","(5)"],["Lower employee compensation and benefits expenses","(5)"],["Miscellaneous expenses","3"],["Year ended December 31, 2022","340"],["Change in Administrative and other","$","4"]] [[/GREPCENT_TABLE]] Depreciation and amortization expense increased $13 million or 3% for the year ended December 31, 2022 compared to year ended December 31, 2021, with the change largely resulting from the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2021","$","404"],["Accelerated depreciation of the Colstrip facility as approved by the OPUC\u2019s 2022 GRC Order","15"],["Capital additions, net of retirements","8"],["Activity related to regulatory programs (offset elsewhere on the income statement)","(10)"],["Year ended December 31, 2022","417"],["Change in Depreciation and amortization","$","13"]] [[/GREPCENT_TABLE]] Taxes other than income taxes expense increased $11 million, or 8%, in 2022 compared with 2021, primarily due to higher franchise fees and property tax expenses. Interest expense increased $19 million, or 14%, in 2022 compared with 2021 driven by higher average balances of outstanding debt as well as higher leasing expenses from the January 1, 2022 commencement of the Pelton/Round Butte financing arrangement. Other income, net increased $5 million, or 19%, in 2022 compared to 2021, with the difference driven by the execution of a buyout of the Non-represented Retiree Medical Plan in 2022, resulting in a $11 million settlement gain. For more information, see Note 11, Employee Benefits, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplemental Data.” An additional $4 million reduction in pension and other post-retirement employee benefit non-service cost expenses also contributed to the increase. The favorable drivers were partially offset by $9 million unfavorable market changes on the non-qualified benefit trust and as well as $3 million lower AFUDC equity income driven by lower construction work-in-progress balances in 2022. Income tax expense increased $16 million, or 70%, in 2022 compared to 2021 primarily driven by a $9 million cumulative catch-up adjustment recorded in 2021 to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax; lower production tax credit benefits in 2022 compared to 2021;higher expenses from flow-through items; and higher pre-tax income. The increases were partially offset by higher research and development tax credit benefits. See Note 12, Income Taxes, in the Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data,” for more information. 59 Table of Contents 2021 Compared to 2020 For a comparison of the Company’s results of operations for the fiscal year ended December 31, 2021 to the year ended December 31, 2020, see Item 7.—” Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 16, 2022. Liquidity and Capital Resources Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan.” in Item 1A.—“Risk Factors,” for further information. Capital Requirements The following table presents actual capital expenditures and debt maturities for 2022 and projected capital expenditures and future debt maturities for 2023 through 2027 (in millions, excluding AFUDC): [[GREPCENT_TABLE]] [["","Years Ending December 31,"],["","2022","","2023","","2024","","2025","","2026","","2027"],["Ongoing capital expenditures (1)","$","801","","","$","785","","","$","725","","","$","750","","","$","775","","","$","800"],["Integrated Operations Center","10","","","10","","","5","","","\u2014","","","\u2014","","","\u2014"],["Clearwater Wind project","$","\u2014","","","$","415","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014"],["Total capital expenditures (2)","$","811","","","$","1,210","","","$","730","","","$","750","","","$","775","","","$","800"],["Long-term debt maturities","$","\u2014","","","$","260","","","$","80","","","$","\u2014","","","$","\u2014","","","$","160"]] [[/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 2022 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 2022, PGE funded its capital expenditures through a combination of cash from operations in the amount of $674 million, and net proceeds from the issuance of FMBs in the total amount of $100 million and a term loan in the amount of $260 million. Capital expenditures in 2023 are expected to be approximately $1.2 billion. PGE plans to fund the 2023 capital expenditures with cash from operations during 2023, which is expected to range from $700 million to $750 million, the issuance of debt securities of up to $350 million, which includes $100 million issued in November 2022 and funded in January 2023, issuances of shares pursuant to an equity forward sale agreement (EFSA), and the issuance of commercial paper, as needed. The actual timing and amount of any other issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7. 60 Table of Contents Liquidity PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves. The following summarizes PGE’s cash flows for the periods presented (in millions): [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2022","","2021"],["Cash and cash equivalents, beginning of year","$","52","","","$","257"],["Net cash provided by (used in):"],["Operating activities","674","","","532"],["Investing activities","(758)","","","(656)"],["Financing activities","197","","","(81)"],["Net change in cash and cash equivalents","113","","","(205)"],["Cash and cash equivalents, end of year","$","165","","","$","52"]] [[/GREPCENT_TABLE]] 2022 Compared to 2021 Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for 2022 compared to 2021 (dollars in millions): [[GREPCENT_TABLE]] [["","Increase/ (Decrease)"],["Net income","$","(11)"],["Other post retirement benefits settlement gain - non-cash","(11)"],["Decoupling mechanism deferrals, net of amortization","(40)"],["Deferral of incremental storm costs in 2021","62"],["Deferral of incremental wildfire costs","(28)"],["2020 Labor Day wildfire earnings test reserve non-cash adjustment to Net income","15"],["Deferral of wildfire mitigation costs","30"],["Accounts receivable and Unbilled revenue","(2)"],["Margin deposits paid to wholesale counterparties due to natural gas commodity prices","(51)"],["Accounts payable","96"],["Margin deposits received from wholesale counterparties due to natural gas commodity prices","24"],["Other miscellaneous changes","58"],["Net change in cash flow from operations","$","142"]] [[/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 2023 will range from $445 million to $465 million. 61 Table of Contents Combined with all other sources, cash provided by operations in 2023 is estimated to range from $700 million to $750 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 in 2023, $47 million in 2024, $28 million in 2025, $27 million in 2026 and $27 million in 2027. 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.” 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 $102 million increase in net cash used in investing activities in 2022 compared with 2021 is primarily due to capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $130 million, offset by a $9 million decrease related to proceeds from the sale of property and a $21 million decrease in other costs of removal related to the 2021 winter storm restoration. The Company plans for $1.2 billion of capital expenditures in 2023 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. PGE plans to fund the 2023 capital expenditures with cash from operations during 2023, as discussed above, as well as with the issuance of debt and equity 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 2022, cash provided by financing activities consisted primarily of the issuance of a $260 million term loan and funding of $100 million in FMBs. In addition, the Company paid dividends in the amount of $158 million, executed a $18 million common stock repurchase, and received proceeds from the Pelton/Round Butte financing arrangement in the amount of $25 million. 2021 Compared to 2020 For a comparison of liquidity and capital resources and the Company’s cash flow activities for the fiscal year ended December 31, 2021 and 2020, 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, 2021, which was filed with the SEC on February 16, 2022. 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 higher fees paid on its revolving credit facility. The Company could also 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 62 Table of Contents 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, 2022, PGE had posted $149 million of collateral with these counterparties, consisting of $116 million in cash and $33 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, 2022, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $55 million and decreases to $1 million by December 31, 2023. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $174 million and decreases to $106 million by December 31, 2023 and $74 million by December 31, 2024. 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, 2022, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $599 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, 2022, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 56.9%. 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 $900 million through February 6, 2024. The following table shows available liquidity as of December 31, 2022 (in millions): [[GREPCENT_TABLE]] [["","December 31, 2022"],["","Capacity","","Outstanding","","Available"],["Revolving credit facility (1)","$","650","","","$","\u2014","","","$","650"],["Letters of credit (2)","220","","","97","","","123"],["Total credit","$","870","","","$","97","","","773"],["Cash and cash equivalents","","","","","165"],["Total liquidity","","","","","$","938"]] [[/GREPCENT_TABLE]] 63 Table of Contents (1)Scheduled to expire September 2027. (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. In September 2022, PGE amended its existing revolving credit facility. As of December 31, 2022, PGE had a $650 million unsecured revolving credit facility scheduled to expire in September 2027. 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 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, 2022, 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, 2022, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2022, 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 $97 million were outstanding as of December 31, 2022. PGE works to optimize its use of its letter of credit facility to manage energy trading margin. Long-term Debt—During 2022, PGE issued and funded a total of $100 million of FMBs. On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in FMBs. The Bonds consist of: •a series, due in 2029, in the amount of $100 million that will bear interest at an annual rate of 5.47%; and •a series, due in 2033, in the amount of $100 million that will bear interest at an annual rate of 5.56%. The 2029 and 2033 Bonds were issued in 2022 and funded in full on November 30, 2022 and January 13, 2023, respectively. On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bears interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 87.5 basis points. The interest rate is subject to adjustment pursuant to the terms of the loan. The loan is prepayable, in whole or in part, without penalty, at any time. The credit agreement expires on October 22, 2023, with any outstanding balance due and payable on such date. The term loan is classified as Current portion of long-term debt on PGE’s consolidated balance sheet. 64 Table of Contents As of December 31, 2022, total long-term debt outstanding, net of $13 million of unamortized debt expense, was $3,646 million, $260 million of which is scheduled to mature in 2023. Equity—On October 25, 2022, PGE entered into an EFSA in connection with the public offering of 10,100,000 shares of its common stock. Effective October 28, 2022, pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock with an initial value of $499 million, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters. PGE receives proceeds from the sale of the common stock when the EFSA is physically settled. As of December 31, 2022, PGE had not transacted under the EFSA. As of December 31, 2022, the Company could have physically settled the EFSA by delivering 11,615,000 shares of PGE common stock to the forward counterparty in exchange for cash of $483 million. The Company anticipates physical settlement of the EFSA by delivery of newly issued shares on or before October 25, 2024. For additional information on the EFSA, see Note 12, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” 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 43.3% and 45.2% as of December 31, 2022 and 2021, respectively. Critical Accounting Policies and Estimates 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. 65 Table of Contents 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. 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, 2022 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. A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate or range of potential loss is material. 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 on contingencies, see Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” 66 Table of Contents