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PORTLAND GENERAL ELECTRIC CO /OR/ - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.

  • Apr 28, 2022
Edgar Glimpses

Forward-Looking Statements

    The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," "should," or similar expressions are intended to identify such forward-looking statements.  Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management's examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE's expectations, beliefs, or projections will be achieved or accomplished.  

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

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

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

•inflation and interest rates;

    •changing customer expectations and choices that may reduce customer demand for its services may impact PGE's ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators;  •the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described under the heading of Regulatory Matters in the Overview section of this Item 2, and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements of this Quarterly Report on Form 10-Q;  •natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability;  •unseasonable or extreme weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers' demand for power and PGE's ability and cost to procure adequate power and fuel supplies to serve its customers, PGE's ability to access the wholesale energy market, PGE's ability to operate its generating facilities and transmission and                                         36 --------------------------------------------------------------------------------   Table of Contents distribution systems, the Company's costs to maintain, repair, and replace such facilities and systems, and recovery of costs;  •PGE's ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk, which could cause damage to the Company's own facilities or 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 projects, any of which could result in the Company's inability to recover project costs;  •volatility in wholesale power and natural gas prices that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;  

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

    •capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE's credit ratings, any of which could have an impact on the Company's cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt;  •future laws, regulations, and proceedings that could increase the Company's costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;  

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

    •the effects of climate change, 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 demand, or demographic patterns, in PGE's service territory;

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

•cybersecurity attacks, data security breaches, physical security breaches, or other malicious acts that cause damage to the Company's generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, 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 coronavirus (COVID-19) pandemic;                                         37 --------------------------------------------------------------------------------   Table of Contents •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 responded to legislative requirements concerning greenhouse gas emission reductions, any of which can 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;

•acts of war or terrorism; and

•risks and uncertainties related to RFP final shortlist projects, including, but not limited to regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including application tariffs impacting solar module imports), and legislative uncertainty.

     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.  


    Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. The MD&A should be read in conjunction with the Company's condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC.  PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. PGE is committed to developing products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.  Company Strategy  The Company exists to power the advancement of society. PGE energizes lives, strengthens communities, and fosters energy solutions that promote social, economic, and environmental progress. The Company is committed to being a clean energy leader and delivering steady growth and returns to shareholders. PGE is focused on working with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing greenhouse gas emissions, and responding to evolving customer expectations. At the same time, the Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region. PGE is transforming all aspects of its business to empower its workforce to be even more results oriented to serve customers well. To create a clean energy future, PGE is focused on the following strategic initiatives:                                         38 --------------------------------------------------------------------------------   Table of Contents •Decarbonize the power supply by reducing GHG emissions associated with the power served to customers by at least 80% by 2030, 90% by 2035, and achieving zero GHG emissions associated with the power served to customers by 2040;  

•Electrify other sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and

•Perform by improving work efficiency, safety of its workforce, and reliability of its systems and equipment, all while adhering to the Company's long-term earnings per diluted share growth guidance of 4-6% on average.

Climate change

    State-mandated GHG reduction targets-In June 2021, the Oregon legislature passed HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the state. A number of provisions in the bill align with PGE's strategic direction, and highlight Oregon's ambitious, economy-wide goals to combat climate change. The GHG reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see the "Environmental Laws and Regulations" section within this Overview.  Empowering customers and communities-PGE's customers are committed to purchasing clean energy, as over 235 thousand residential and small commercial customers voluntarily participate in PGE's Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon's most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE's service area continue to consider similar goals.  The Company implemented a customer service option, the Green Future Impact (GFI) Program, which is a renewable energy program that allows customers to have a choice in how they source their electricity. Under the GFI Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option. Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PGE-Supplied option, 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 March 31, 2022, the GFI Program has an approved capacity of 750 MW. 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.

    Extreme weather-In recent years, PGE's territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. In June 2021, temperatures in the region reached all-time recorded highs, shattering the Company's previous peak load demand, and surpassing the prior summer peak load by nearly 12%. In February 2021, PGE's service territory experienced an ice storm, which 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). In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned (see "Wildfire" 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.                                          39 --------------------------------------------------------------------------------   Table of Contents Investing in a clean energy future  Building a resilient grid-Recent extreme weather events driven by changes to global systems affecting rainfall patterns and seasonal snow cover in the region have impacted PGE's customers significantly, and the frequency and severity of these events are accelerating. PGE's grid of the future is increasingly smart and adaptive, so that the electric service its customers depend on remains reliable even under uncertain and extreme conditions. For example, the Company uses wireless smart sensors and centrally controlled automated switches to help isolate disruptions and more quickly reroute power, preventing or shortening disruptions. In the field, PGE uses advanced data analytics to optimize system investments and maintenance. The Company is updating its design standards, so that smart sensors and switches are constructed to withstand more extreme weather, particularly in high-risk wildfire areas.  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. With the passage of House Bill 2021, PGE will prepare a Clean Energy Plan (CEP) which will articulate the Company's strategy to meet the 2030 and 2040 decarbonization targets. The first CEP is anticipated to be filed in the Spring of 2023 and will set annual decarbonization targets and articulate how PGE will achieve an equitable transition to a decarbonized grid. PGE's resource planning analysis and stakeholder engagement will continue to occur through the Integrated Resource Plan (IRP) and Distribution System Plan (DSP) processes.  

PGE's 2016 IRP process resulted in the development of the following renewable resources:

    •Wheatridge Renewable Energy Facility (Wheatridge)-In 2018, the Company issued a request for proposals (RFP) seeking to procure approximately 100 average megawatts (MWa) of qualifying renewable resources. The prevailing project was Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage. PGE owns 100 MW of the wind resource, which was placed in-service in 2020. Subsidiaries of NextEra Energy Resources, LLC operate the facility and own the balance of the wind resource, along with the solar and battery components, which were placed in-service in March of 2022, and sell their portion of the output to PGE.  In May 2020, PGE obtained an OPUC order acknowledging the Company's 2019 IRP and associated Action Plan for PGE to acquire resources over the next four years, an important step in acquiring the necessary clean and renewable and capacity resources by 2030. In October 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable and non-emitting resources. PGE estimates that the 2021 All-Source RFP will meet a portion of the Company's projected need of approximately 1,500 to 2,000 MW of clean and renewable resources and approximately 800 MW of non-emitting dispatchable capacity resources in order to meet the Company's 2030 emissions reduction target. PGE also expects it will need to exit Colstrip and is actively working on plans to achieve this by the end of 2025.  

The All-Source RFP seeks:

•Approximately 375 to 500 MW of renewable resources;

•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 (GFI) Program. Under the GFI Program, PGE plans to acquire up to 100 MW of a new wind, solar, or hybrid renewable and battery storage resources to meet subscriber demand under the PGE supply option. The Company does not expect GFI Program resources considered in the 2021 All-Source RFP to contribute towards the 150 MWa renewable energy target envisioned under the 2019 IRP Action Plan.  PGE will work with the OPUC to evaluate whether procuring resources beyond the amounts identified above are in the best interest of customers given the significant new clean resources additions necessary to meet HB 2021 requirements in 2030.                                         40 --------------------------------------------------------------------------------   Table of Contents Renewable resources in PGE's 2021 All-Source RFP must be eligible under Oregon's Renewable Portfolio Standard (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.  PGE issued the final RFP after receiving approval with modifications from the OPUC in December 2021, and proposals were submitted in January 2022. Bids were evaluated based on the OPUC-approved scoring methodology. Following determination of a final shortlist, PGE plans to submit a request for acknowledgement of the shortlist to the OPUC on May 5, 2022 that includes seven distinct projects submitted by five bidders for renewable resources and six distinct projects by four bidders for capacity resources.  The proposals for renewable resources provide various combinations of wind, solar, and battery storage options that include power purchase agreements (PPA) along with Company-owned resources. The proposals for non-emitting capacity resources provide battery storage and pumped storage options that include PPAs along with Company-owned resources. The ultimate outcome of the RFP process may involve the selection of multiple projects for both renewable and capacity resources.  PGE will request that the OPUC acknowledge the RFP shortlist by July 15, 2022 to enable the Company to execute definitive agreements. RFP final shortlist projects were evaluated and selected based on conditions as of the shortlist date. PGE intends to commence negotiations with one or more bidders and finalize negotiations prior to the end of 2022 to allow sufficient time to capture expiring federal tax credits for the benefit of customers.  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 RFP. PGE has joined in the case as an intervenor. NewSun also filed a motion to stay the RFP process, which the Court subsequently denied. The OPUC has filed a motion to dismiss the case and PGE has joined the OPUC's motion to dismiss. NewSun opposes the motion. PGE cannot predict the outcome of the proceeding or potential impact, if any, to its ongoing RFP process.  In October 2021, PGE filed its inaugural Distribution System Plan (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 is expected to be filed in August of 2022.  

In October 2021, PGE filed an extension waiver for the next IRP that the OPUC approved. As a result, the next IRP will be filed for OPUC consideration by March 31, 2023.

    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.  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 the State's carbon reduction goals. In 2020, the OPUC approved the plan and related costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. In 2021, the Oregon legislature enacted House Bill 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification.                                        41


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    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.  

Environmental Laws and Regulations

    House Bill 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, compared to their baseline emissions levels by 80% by 2030, 90% by 2035, and 100% by 2040. The baseline emissions levels for the investor-owned utilities are the average annual GHG emissions for the years 2010, 2011, and 2012 associated with the electricity sold to their retail electricity consumers as reported to the Oregon Department of Environmental Quality (ODEQ).  Utilities must develop a clean energy plan (CEP) for meeting the targets concurrent with the development of each IRP. In reviewing the CEP, the OPUC must ensure that utilities demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions and the transition to an equitable grid at reasonable costs to retail electricity consumers. The OPUC is also given authority to apply a performance incentive for early compliance with one or more of the clean energy targets.  Regulated entities will continue to report annual GHG emissions to ODEQ, as they do today. In compliance years, which are 2030, 2035, and 2040 and every year thereafter, the OPUC will use the data reported to ODEQ for that compliance year to determine whether the reduction targets are met. In determining compliance, if the utility has emissions in excess of the target, the OPUC must take into consideration unplanned emissions necessary to meet load if the utility experienced unexpected challenges, such as transmission constraints or under-production from hydro and other renewable resources. The bill also includes certain compliance exceptions to protect customers, including a cost cap and the ability for the OPUC to grant a temporary exemption if a utility is unable to comply with mandatory reliability standards.  

The legislation also:

•Aligns with PGE decarbonization goals while protecting affordability and reliability;

•Establishes clear decarbonization authority for the OPUC, including authority over ESSs;

•Modernizes competition provisions of Oregon's electricity restructuring law from 1999, Oregon Senate Bill 1149 (SB 1149),

    •Provides clear authority and process for a community-wide green tariff program for customers 30 kilowatts and smaller and allows utilities the ability to earn a return on investments in program resources, and  

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

Governor Executive Orders-In 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions.

Among other things, the executive order:

•Directed state agencies to integrate climate change and the State's GHG emissions reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law;

•Directed the OPUC to-



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•determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon's reduction goals;

•encourage electric companies to support transportation electrification infrastructure that supports GHG emissions reductions and zero-emission vehicle goals; and

    •prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy;  

•Directed the ODEQ to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. The ODEQ adopted such a program, referred to as the Climate Protection Plan, in December 2021; and

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

    RPS Standards and Other Laws-In 2016, Oregon Senate Bill 1547 (SB 1547) set a benchmark for how much electricity must come from renewable sources and required the elimination of coal from Oregon utility customers' energy supply no later than 2030 (subject to an exception that allowed extension of this date until 2035 for PGE's output from Colstrip).  

Other provisions of the law include:

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

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

•An allowance for energy storage costs related to renewable energy in the Company's Renewable Adjustment Clause (RAC) filings.

    In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE's investment in 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 two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2.  Although PGE is currently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in their respective jurisdictions. In December 2021, the OPUC approved PGE's depreciation study (OPUC Docket UM 2152), which will accelerate depreciation on Colstrip through December 31, 2025. Depreciation rates will change and customer collection would coincide with the price effective date of the Company's 2022 General Rate Case (2022 GRC). For further information on the 2022 GRC, see "General Rate Case" in the "Regulatory Matters" section of this Overview. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of PGE's exit from the generation facility. See Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements" for information regarding legal proceedings related to Colstrip.  Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in the Pacific Northwest and neighboring states. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission                                        43


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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 Case-In July 2021, PGE filed with the OPUC a general rate case based on a 2022 test year. The filing requested an increase in PGE's annual revenue requirement that, when combined with changes in supplemental schedules, would result in an overall average increase of approximately 3.9% in customer prices for 2022. The net price increase and annual revenue requirement included a 2.0% average price increase as a result of higher net variable power costs (NVPC) expected in 2022, as reflected in the Annual Update Tariff (AUT) filed with the OPUC in April 2021. The 2022 GRC filing sought recovery of base business investments in upgrading the grid to improve reliability, resiliency, and capability to deliver safe, reliable, clean electricity to customers.  PGE has invested heavily in its transmission and distribution system to meet the needs of customers by addressing new and growing load and strengthening the grid for new challenges with extreme weather and wildfires. These investments include needed pole and underground wire replacements, substation upgrades, and other additions, as well as the new Integrated Operations Center and the Advanced Data Management System software platform.  The 2022 GRC also reflected significant investments geared toward protecting the lives and property of Oregonians. As Oregon's weather gets hotter and drier, increasing the risk of catastrophic wildfires, the Company is intensifying efforts to keep the system safe from wildfire-related events and resilient from weather and disaster-related crises. Key to these efforts are expansion of the vegetation management program and system hardening to help mitigate potential outages arising from wildfire and severe weather year-round.  

The proposed net increase in annual revenue requirement in the 2022 GRC was based upon:

•A capital structure of 50% debt and 50% equity;

•A return on equity of 9.5%;

•A cost of capital of 6.94%; and

•A rate base of $5.7 billion.

PGE, OPUC staff, and certain customer groups reached an agreement that resolved cost of capital issues and allowed for:

•A capital structure of 50% debt and 50% equity;

•A return on equity of 9.5%; and

•A cost of capital of 6.83%, which reflects updates for actual and forecasted debt costs.

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

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



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    As filed (includes $40 million related to NVPC)                               $     99 Load and NVPC Updates                                                       


Base Business Revenue Requirement Updates:

Faraday hydro capital-related revenue requirement (1)


Cost of debt settlement including reductions to reflect actual financing costs

                                            (7)    Level III outage annual regulatory accrual (2)                       (7) 

Other reductions to rate base and operating and maintenance expenses

                                                      (5)    Other various modifications to reflect actual costs                  (4)      Subtotal                                                              


   As revised (includes $64 million related to NVPC) (3)                       

$ 74

     (1) The Faraday improvement capital project will not be placed in-service as of May 9, 2022, and the capital-related revenue requirement was removed and can be addressed in the next GRC proceeding. As of March 31, 2022, the construction work-in-progress balance associated with Faraday was $116 million, including an allowance for funds used during construction (AFUDC).  (2) PGE is authorized to collect annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In the 2022 GRC, the Company requested an annual collection increase from $4 million to $11 million, and agreed to retain the annual collection at $4 million.  

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

    Further, the parties agreed to eliminate PGE's decoupling mechanism upon the effective date of new customer prices pursuant to this case. Throughout the remainder of 2022, estimated collections from, or refunds to, customers will be pro-rated based on the effective date of new customer prices per the 2022 GRC and expected to be amortized in customer prices in 2024 over a one-year period. The decoupling mechanism provides a means of recovery or refund of margin lost or gained as a result of changes in weather-adjusted energy use per customer in comparison to levels projected in customer prices. For further information on the decoupling mechanism, see "Decoupling" in this Overview section. On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism. Key elements of the OPUC's Order also included: •establishment of a balancing account for the Company's major storm damage recovery mechanism; •denial of PGE's proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project. PGE can pursue recovery in the Company's next GRC; •establishment of a deferral that would require 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 •creation of an earnings test for the deferrals for the 2020 Wildfire Emergency and the February 2021 Ice Storm and Damage that is to be applied on a year-by-year basis.  As a result of the earnings tests outlined in the OPUC's Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended March 31, 2022 in the estimated amount of $17 million. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC for 2021 and 2022.  New customer prices as approved by the OPUC will become effective May 9, 2022. Price changes for the AUT and the supplemental schedules items occurred January 1, 2022.                                         45 --------------------------------------------------------------------------------   Table of Contents Complete details of the 2022 GRC filing (OPUC Docket UE 394) and the resulting OPUC Order are available on the OPUC Internet website at  COVID-19 Impacts-The COVID-19 pandemic has had a variety of adverse impacts on economic activity. The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. As a result of these activities and economic hardships, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs.  In March 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC's jurisdiction, intervenors, and OPUC Staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under 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 March 31, 2022 and December 31, 2021, PGE's deferred balance was $35 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE expects incremental bad debt expense to be $16 million to $18 million for the year-ended 2022. PGE expects to cease deferring incremental bad debt expense associated with customers who are not on a time payment arrangement, after September 30, 2022. Pursuant to the earnings tests outlined in the OPUC's Order in the 2022 GRC, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the estimated amount of $2 million. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings review.  PGE believes the 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, including an earnings review, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.  Wildfire-In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE's wildfire mitigation planning includes regular system-wide risk assessment, which led to the identification and activation of a PSPS in a zone near Mt. Hood that was identified as a region at high risk of wildfire in 2020. Additionally, in response to wildfires across Oregon in 2020, PGE cut power to eight additional high-risk fire areas in partnership with local and regional agencies. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment.  The Company is intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises. These efforts include enhanced tree and brush clearing, replacing equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. Pursuant to Oregon Senate Bill 762, which was passed in June 2021, PGE submitted a risk-based wildfire protection plan to the OPUC in December 2021. In Order 22-129, the OPUC did not adopt any rate adjustment mechanisms, but rather invited PGE to submit a filing proposing a cost                                        46 --------------------------------------------------------------------------------   Table of Contents recovery mechanism for incremental wildfire costs consistent with SB 762 and establishing an ongoing review for reasonableness.  PGE continues to incur costs to address fire-damaged vegetation, debris and hazards both in and outside of PGE's property and right-of-way, and other wildfire mitigation costs. In October 2020, the OPUC formally approved PGE's request for deferral of 2020 wildfire-related costs. As of March 31, 2022 and December 31, 2021, PGE's cumulative deferred costs related to the 2020 wildfire response was $38 million and $45 million, respectively. Pursuant to the earnings tests outlined in the OPUC's Order in the 2022 GRC, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the estimated amount of $15 million.  

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. Through March 31, 2022, PGE has incurred an estimated $108 million in incremental costs due to the storms, of which $36 million were capital and recorded to Electric utility plant, net and $72 million were operating expenses associated with transmission and distribution.  Beginning in 2019, the OPUC authorized the Company to collect $4 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In the first quarter of 2021, PGE exhausted its storm collection balance for 2021 of $9 million, which was used to offset operating expenses. In December 2021, PGE and parties in the 2022 GRC reached a settlement, subject to OPUC approval, to restore the storm collection balance for the $9 million used in 2021 and to defer the resulting balance of $9 million into the February 2021 ice storm and damage regulatory asset.  On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) and as of March 31, 2022, the Company has deferred a total of $71 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 in the first quarter of 2022. While the Company believes the full amount of the deferral is probable of recovery given PGE's prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusion of overall prudence, including an earnings test, 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.  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 use deferred accounting to track incremental costs related to the emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices including a review of utility prudence in a future proceeding, among other requirements. PGE has not recorded any costs under this deferral order.                                        47


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    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. For 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the Company's power cost adjustment mechanism (PCAM) and related earnings test, PGE has deferred 90% of the excess variance for 2021, or $28 million, which is expected to be collected from customers. See "Power Operations" within this Overview section of Item 2 for more information regarding the PCAM.  Portland Harbor Environmental Remediation Account (PHERA) Mechanism-The U.S. Environmental Protection Agency (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 March 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 issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. Stakeholders have raised concerns that EPA's cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company's liability related to the cost of remediating Portland Harbor could be material to PGE's financial position. The impact of such costs to the Company's results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company's recovery mechanism allows the Company to defer and recover estimated liabilities and incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including, but not limited to, insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE's results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see "EPA Investigation of Portland Harbor" in Note 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements."  Decoupling-The decoupling mechanism, authorized by the OPUC through 2022, 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 collections recorded in 2022, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 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 had resulted in larger estimated refunds under the decoupling mechanism, which had largely offset the revenue increases that had 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 are expected to begin May 9, 2022. Pursuant to the GRC

                                         48 --------------------------------------------------------------------------------   Table of Contents Order, the OPUC adopted the agreement such that deferrals will cease, although amortization of previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices.  For the three months ended March 31, 2022, the Company recorded an estimated refund of $2 million and a collection of $1 million from residential and commercial customers, respectively, that resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company continues to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by the COVID-19 pandemic.  

As of December 31, 2021, PGE had recorded a total estimated refund of $10 million that, subject to OPUC approval, will be refunded to customers over a one-year period, which would begin 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 Boardman currently included in customer prices as established in the Company's 2019 GRC. The application stated a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. In October 2021, intervenors filed a motion with the OPUC requesting to consolidate the open Boardman deferral docket with PGE's open 2022 GRC docket. The Administrative Law Judge denied the consolidation, although did provide an opportunity to use the 2022 GRC proceeding to settle any issues with deferrals.  PGE estimated the revenue requirement for Boardman to be $14 million for the period ended December 31, 2020 plus an additional $66 million for the year ended December 31, 2021 and $17 million for the three months ended March 31, 2022.  In the 2022 GRC Order, the OPUC found that the deferral was warranted with amortization subject to an earnings test. Based on the earnings test, PGE does not expect to record a refund related to Boardman. Customer prices resulting from the 2022 GRC Order will no longer include any revenue requirement related to Boardman when new customer prices take effect on May 9, 2022.  Renewable Recovery Framework-As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. There have been no significant filings made under the RAC during 2022.  Operating Activities  In combination with electricity provided by its own generation portfolio, to meet its retail load requirements and balance its energy supply with customer demand, PGE purchases and sells electricity in the wholesale market. The Company also performs portfolio management and wholesale market sales services for third parties in the region. PGE also participates in the California Independent System Operator's Western Energy Imbalance Market, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market.  The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company's revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on                                        49 --------------------------------------------------------------------------------   Table of Contents revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.   Customers and Demand-The following tables present total energy deliveries and the average number of retail customers by customer type for the periods indicated.                                                                         Three Months Ended March 31,      % Increase (Decrease)                                                                                                                in Energy                                                                                                   2022        Deliveries           2021  Energy deliveries (MWhs in thousands): Retail: Residential                                                                                                        2,216                      2,239           (1) % Commercial                                                                                                         1,634                      1,564            4  % Industrial                                                                                                           974                        897            9  % Subtotal                                                                                                           4,824                      4,700            3  % Direct access: Commercial                                                                                                           131                        150          (13) % Industrial                                                                                                           413                        359           15  % Subtotal                                                                                                             544                        509            7  % Total retail energy deliveries                                                                                     5,368                      5,209            3  % Wholesale energy deliveries                                                                                        1,507                      1,245           21  % Total energy deliveries                                                                                            6,875                      6,454            7  %                                                                           Three Months Ended March 31,                                                                                      2022                          2021  Average number of retail customers: Residential                                                                                       806,553          88  %             797,602     88  % Commercial                                                                                        111,668          12                110,703     12 Industrial                                                                                            192           -                    193      - Direct access                                                                                         550           -                    601      - Total                                                                                             918,963         100  %        909,099         100  %   

Total retail energy deliveries for the three months ended March 31, 2022 increased 3% compared with the three months ended March 31, 2021, driven by strong demand from the industrial customer class.

    The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from the COVID-19 pandemic closures than other sectors. Residential usage continues to be elevated as remote and hybrid work schedules remain in place across the Company's service area, although total deliveries declined slightly, reflecting the impact of relative temperatures as 2022 had fewer heating degree-days.  The following table indicates the number of heating degree-days for the three months ended March 31, 2022 and 2021, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:                                        50


    Table of Contents                                                           Heating Degree-days                                                      2022              2021         Avg.        January                                              710          620          721       February                                             591          641          598       March                                                460          544          527        Year-to-date                                       1,761        1,805        1,846       (Decrease) from the 15-year average                   (5) %        

(2) %

      After adjusting for the effects of weather, retail energy deliveries for the three months ended March 31, 2022 increased 4.4% compared to the same period of 2021. The increase reflects increases of 10% in industrial deliveries, 3% in commercial energy deliveries, and 2% in residential energy deliveries. Residential weather-adjusted average usage per customer ticked up slightly during the first quarter 2022 compared with 2021, while growth of 1.1% in the average number of residential customers contributed to the increased energy deliveries in total.  The Company's cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. This cap would have limited energy deliveries to these customers to an amount equal to approximately 12% of PGE's total retail energy deliveries for the first three months of 2022.  In early February 2020, PGE began offering service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 17% of the Company's energy deliveries could have been supplied by ESSs. Actual energy deliveries to Direct Access customers by ESSs represented 10% of PGE's total retail energy deliveries for the first three months of 2022 and 2021.  Power Operations-PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. As a result, the amount of power generated and purchased in the wholesale market to meet the Company's retail load requirement can vary from period to period and impacts NVPC and income from operations.  The following table provides information regarding the performance of the Company's generating resources for the three months ended March 31, 2022 and 2021:                                                                           Actual energy provided                   Actual energy provided as a                                                                            compared to projected                   percentage of total retail                                         Plant availability (1)                  levels (2)                                    load                                            2022             2021                           2022           2021                        2022          2021 Generation: Thermal: Natural gas                                      92  %         94  %                          79  %         114  %                       42  %         48  % Coal (3)                                         96            94                            110            103                          12            12 Wind (4)                                         74            94                             83            129                           8            11 Hydro                                            96            85                             81             81                           5             6   (1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2)Projected levels of energy are included as part of PGE's AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources.                                        51


Table of Contents (3)Plant availability reflects Colstrip, which PGE does not operate. (4)Plant availability excludes Wheatridge, which PGE does not operate.

    Energy received from PGE-owned and jointly-owned thermal plants during the three months ended March 31, 2022 compared to 2021 decreased 7%. In 2022 generation at the Company's natural gas-fired plants decreased due to less favorable gas prices, partially offset by an increase in coal-fired generation. 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 hydroelectric generation sources, both PGE-owned generation and purchased, increased 27% during the three months ended March 31, 2022 compared to 2021. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 38% and energy generated by the Company-owned facilities decreased 14% in the three months ended March 31, 2022 partially due to PGE's sale of 16.66% of its ownership interest in Pelton/Round Butte to the Confederated Tribes of the Warm Springs Reservation of Oregon (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 2, for further detail on regional hydro results.  Energy received from PGE-owned wind resources and under contracts decreased 24% during the three months ended March 31, 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 PGE's PCAM, the Company may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed "deadband" limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE's actual regulated return on equity (ROE) for the given year being no less than 1% above the Company's latest authorized ROE, while a collection will occur only to the extent that it results in PGE's actual regulated ROE for that year being no greater than 1% below the Company's authorized ROE. The following is a summary of the results of the Company's PCAM as calculated for regulatory purposes for the three months ended March 31, 2022 and 2021, respectively:  •For the three months ended March 31, 2022, actual NVPC was $10 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2022 is currently estimated to be below the baseline, and within the established deadband range. Accordingly, no estimated refund to customers is expected under the PCAM for 2022.  •For the three months ended March 31, 2021, actual NVPC was $13 million below baseline NVPC. For the year ended December 31, 2021, actual NVPC was $62 million above baseline NVPC, 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 PGE deferred $28 million, which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.                                         52


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Results of Operations

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

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

                                                                             Three Months Ended March 31,               % Increase                                                                                                            2022     (Decrease)        2021 Total revenues                                                                                                   $         626                    $  609                   3  % Operating expenses: Purchased power and fuel                                                                                                   202                       169                  20  % Generation, transmission and distribution                                                                                   90                        80                  13  % Administrative and other                                                                                                    89                        86                   3  % Depreciation and amortization                                                                                               99                       103                  (4) % Taxes other than income taxes                                                                                               40                        38                   5  % Total operating expenses                                                                                                   520                       476                   9  % Income from operations                                                                                                     106                       133                 (20) % Interest expense, net*                                                                                                      38                        34                  12  % Other income: Allowance for equity funds used during construction                                                                          3                         4                 (25) % Miscellaneous income, net                                                                                                    -                         2                (100) % Other income, net                                                                                                            3                         6                 (50) % Income before income tax expense                                                                                            71                       105                 (32) % Income tax expense                                                                                                          11                         9                  22  % Net income                                                                                                       $          60                    $   96                 (38) %  

* Includes an allowance for borrowed funds used during construction of $2 million for the three months ended March 31, 2022 and 2021, respectively.

    Net income for the three months ended March 31, 2022 decreased $36 million from the comparable period of 2021. Total revenues increased as a result of higher retail energy deliveries, primarily driven by continued growth in industrial demand, including high-tech manufacturing. The revenue increase also reflects price increases authorized by the OPUC as a result of the AUT, which are offset by higher power costs. The impact of higher natural gas and wholesale electricity prices coupled with increased customer demand also drove Purchased power and fuel expense up. 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 increased primarily due to higher market prices. Increases in Operating expenses reflect $17 million of previously deferred items that were disallowed as a result of the 2022 GRC order from the OPUC, and expenses related to service restoration costs and continued vegetation management activities. Higher relative Income tax expense in 2022 reflects the favorable impact of a local tax flow-through adjustment that occurred in 2021.                                        53


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    Total revenues consist of the following for the periods presented (dollars in millions):                                                                Three Months Ended March                                                                         31,                                                                       2022                    2021  Retail: Residential                                                                   $  308          49  %       $  310         51  % Commercial                                                                       178          29             162         26 Industrial                                                                        69          11              60         10 Direct Access*                                                                     8           1              11          2 Subtotal                                                                         563          90             543         89 Alternative revenue programs, net of amortization                                  1           -              (3)         - Other accrued revenues, net                                                        -           -              13          2 Total retail revenues                                                            564          90             553         91 Wholesale revenues                                                                56           9              33          5 Other operating revenues                                                           6           1              23          4 Total revenues                                                                $  626         100  %       $  609        100  %   

* Commercial revenues from Direct Access customers were $3 million for 2022 and $4 million for 2021, respectively. Industrial revenues from Direct Access customers were $5 million and $7 million for 2022 and 2021, respectively.

    Total retail revenues-The following items contributed to the increase in Total retail revenues for the three months ended March 31, 2022 compared to the same period in 2021 as follows (dollars in millions):                                                                                 Three Months Ended March 31, 2021                                                                $               553 

Increase as a result of the AUT, approved by the OPUC (offset in Purchased power and fuel)


Increase from higher retail energy deliveries driven by customer load growth


Increase resulting from the combination of various supplemental tariffs and adjustments

                                                                                   1   Recovery in Revenues of Storm related expenses in 2021                                      (11) 

Decrease as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19 and increased industrial demand


Decrease attributed to alternative revenue programs related to the decoupling mechanism due primarily to increased residential use per customer

                                                                                         (3) March 31, 2022                                                                $               564 Change in Total retail revenues                                               $                11    Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company's efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand.  For the three months ended March 31, 2022, Wholesale revenues increased $23 million, or 70%, from the three months ended March 31, 2021 as a $16 million increase from 16% higher average wholesale sales price was combined with a $7 million increase due to a 21% increase in sales volumes. The higher prices have resulted from the overall economic recovery and macroeconomic factors impacting the energy commodity markets.                                         54 --------------------------------------------------------------------------------   Table of Contents Other operating revenues were down $17 million for the three months ended March 31, 2022 compared with the same period in 2021. In the three months ended March 31, 2021, market conditions allowed the Company to sell excess natural gas not needed to fuel generation at a gain of $10 million, whereas in 2022 such excess gas was sold at a $6 million loss.  Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE's retail load requirements, as well as the cost of settled electric and natural gas financial contracts.  The following items contributed to the change in Purchased power and fuel for the three months ended March 31, 2022 compared to the same period in 2021 (dollars in millions, except for average variable power cost per Megawatt hours (MWh)):                                                                   Three Months Ended   March 31, 2021                                                 $               169   Increase related to average variable power cost per MWh                          3   Increase related to total system load                                           30    March 31, 2022                                                                 202   Change in Purchased power and fuel                             $                33    Average variable power cost per MWh:   March 31, 2021                                                 $             27.14   March 31, 2022                                                 $             30.34    Total system load (MWhs in thousands):   March 31, 2021                                                                 6,237   March 31, 2022                                                                 6,648    For the three months ended March 31, 2022, the $3 million increase related to the change in average variable power cost per MWh was driven by a 5% increase in the average cost of purchased power, offset with a 9% decrease on the average cost for the Company's own generation. The $30 million increase related to total system load was primarily due to a 33% increase in deliveries of energy obtained from purchased power resulting from the economic displacement of gas facilities in the first quarter of 2022, in addition to increased retail load demand. This was offset by a 10% decrease in the Company's own generation.                                        55


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

Three Months Ended March 31,

                                                                                            2022                          2021 Sources of energy (MWhs in thousands): Generation: Thermal: Natural gas                                                                                                     2,149             32  %         2,383             38  % Coal                                                                                                              610              9              582              9 Total thermal                                                                                                   2,759             41            2,965             47 Hydro                                                                                                             273              4              317              5 Wind                                                                                                              392              6              532              9 Total generation                                                                                                3,424             51            3,814             61 Purchased power: Hydro*                                                                                                          1,562             23            1,129             18 Wind*                                                                                                             195              3              238              4 Solar*                                                                                                            113              2               92              1 Natural Gas                                                                                                         2              -                4              - Waste, Wood and Landfill Gas*                                                                                      37              1               39              1 Source not specified                                                                                            1,315             20              921             15 Total purchased power                                                                                           3,224             49            2,423             39 Total system load                                                                                               6,648            100  %         6,237            100  % Less: wholesale sales                                                                                          (1,507)                         (1,245) Retail load requirement                                                                                         5,141                           4,992    *Includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) of 6 MWh in 2022 and 2021 from Hydro resources, 6 MWh in 2022 and 2021 from Wind resources, 104 MWh in 2022 and 88 MWh in 2021 from Solar resources, and 20 MWh in 2022 and 19 MWh in 2021 from Waste, Wood and Landfill Gas resources.  

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

Runoff as a Percent of Normal*

                           Location                              2022 Forecast                   2021 Actual Columbia River at The Dalles, Oregon                                       95  %                           82  % Mid-Columbia River at Grand Coulee, Washington                            103                              89 Clackamas River at Estacada, Oregon                                       104                              70 Deschutes River at Moody, Oregon                                           92                              84   

* 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.

                                         56 --------------------------------------------------------------------------------   Table of Contents Actual NVPC for the three months ended March 31, 2022 increased compared to the same period in 2021 as follows (dollars in millions):                                                       Three Months Ended               March 31, 2021                         $               136               Purchased power and fuel expense                        33               Wholesale revenues                                     (23)               March 31, 2022                         $               146               Change in NVPC                         $                10    For further information regarding NVPC in relation to the PCAM, see "Purchased power and fuel expense" and "Revenues" within this "Results of Operations" for more details.  

For the three months ended March 31, 2022 and 2021, actual NVPC was $10 million and $13 million below baseline NVPC, respectively.

    Based on forecast data, NVPC for the year ending December 31, 2022 is currently estimated to be below the baseline, and within the deadband. Accordingly, no estimated refund to customers is expected under the PCAM for 2022.  Generation, transmission and distribution increased as follows for the three months ended March 31, 2022 compared to the same period in 2021 (dollars in millions):                                                                                 Three Months Ended March 31, 2021                                                                $                80

Release of previously deferred amounts pursuant to April OPUC 2022 GRC



Higher distribution vegetation management, inspection, and maintenance expenses

                                                                                          8 February 2021 wind and ice storm restoration expenses                                         (13) Miscellaneous expenses                                                                         (1) March 31, 2022                                                                $                90 Change in Generation, transmission and distribution                           $                10    

PGE experienced higher Generation, transmission and distribution expenses largely from vegetation management activities coupled with a strong labor market and rising cost of materials and supplies.

Administrative and other increased for the three months ended March 31, 2022 compared to the same period in 2021 as follows (dollars in millions):

                                                                  Three Months 


       March 31, 2021                                           $                86      Higher employee compensation and benefits expenses                         2      Lower professional service expenses                                       (1)      Miscellaneous expenses                                                     2      March 31, 2022                                           $                89      Change in Administrative and other                       $                 3    Higher Administrative and other expenses reflect increases for employee wage and benefit expenses and outside services, including labor, driven by a strong labor market, as well as the cost of materials.                                         57 --------------------------------------------------------------------------------   Table of Contents Depreciation and amortization expense decreased $4 million in the three months ended March 31, 2022 compared to the same period in 2021, driven by an $8 million decrease due to regulatory amortization, partially offset by higher depreciation from net plant additions.  

Taxes other than income taxes expense increased $2 million in the three months ended March 31, 2022 compared with 2021, driven by higher franchise tax expenses.

Interest expense, net increased $4 million in the three months ended March 31, 2022 compared to the same period in 2021 due to higher leasing expenses and higher long-term debt balances.

    Other income, net decreased $3 million for the three months ended March 31, 2022 compared to the same period in 2021. The decrease was driven by unfavorable market changes on the non-qualified benefit trust, partially offset by higher interest income on regulatory deferral balances.  Income tax expense increased $2 million for three months ended March 31, 2022, compared to the same period in 2021. The increase was driven by a cumulative catch-up adjustment recorded in the first quarter of 2021 to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax. The increase was partially offset by lower 2022 pre-tax income. See Note 10, Income Taxes, in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements," for more information.  

Critical Accounting Policies and Estimates

    There have been no material changes to the Company's critical accounting policies and estimates as previously disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 17, 2022.  



    PGE's access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company's current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE's liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company's forward positions and the corresponding price curves.  The following summarizes PGE's cash flows for the periods presented (dollars in millions):                                                                     Three Months Ended March 31,                                                                     2022                   2021 Cash and cash equivalents, beginning of period               $            52          $        257 Net cash provided by (used in): Operating activities                                                     249                   168 Investing activities                                                    (154)                 (162) Financing activities                                                     (37)                 (128) Increase (decrease) in cash and cash equivalents                          58                  (122) Cash and cash equivalents, end of period                     $           110          $        135                                           58


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