# PORTLAND GENERAL ELECTRIC CO /OR/ (POR) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from PORTLAND GENERAL ELECTRIC CO /OR/'s 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/784977/000078497724000034/por-20231231.htm Accession: 0000784977-24-000034 Filing date: 2024-02-20 Report date: 2023-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Company profile: /company/POR/ All MD&A years: /company/POR/mda/ Previous year: /company/POR/mda/fy2022/ (FY 2022) Next year: /company/POR/mda/fy2024/ (FY 2024) ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Forward-Looking Statements The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, 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,” “based on,” “conditioned upon,” “considers,” “could,” “expected,” “forecast,” “goals,” “needs,” “promises,” “subject to,” “targets,” or similar expressions are intended to identify such forward-looking statements. Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished. In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include: •governmental policies, legislative action, and regulatory audits, investigations and actions, including those of the FERC, the OPUC, the SEC, and the Division of Enforcement of the Commodity Futures Trading Commission (CFTC) with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs, and capital investments, energy trading activities, and current or prospective wholesale and retail competition; •economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts; •inflation and volatility in interest rates; •changing customer expectations and choices that may reduce customer demand for PGE’s services may impact the Company’s ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered ESSs or the adoption of community choice aggregation; •the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 7. and Note 19, Contingencies in the 39 Table of Contents Notes to Consolidated Financial Statements in Item 8.— “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K; •natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability; •unseasonable or severe weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers’ demand for power and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, access the wholesale energy market, or operate its generating facilities and transmission and distribution systems, and the Company’s costs to maintain, repair, and replace such facilities and systems, and recovery of costs; •PGE’s ability to effectively implement a PSPS and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems are involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through rates or insurance, resulting in impact to the financial condition or reputation of the Company; •operational factors affecting PGE’s power generating facilities and battery storage facilities, including forced outages, fires, 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 fuel, 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, inability to complete negotiations on contracts for capital projects, 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, or impact PGE’s competitive position, market share, or results of operations in a material way; •volatility in wholesale power and natural gas prices, including but not limited to volatility caused by macroeconomic and international issues, that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements; •changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company’s power costs; •capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, volatility of equity markets as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees; •future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions; •changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife; 40 Table of Contents •the effects of climate change, whether global or local in nature, including unseasonable or extreme weather and other natural phenomena that may affect energy costs or consumption, increase the Company’s costs, cause damage to PGE facilities and system, or adversely affect its operations; •changes in residential, commercial, or industrial customer growth, or demographic patterns, including changes in load resulting in future transmission constraints, in PGE’s service territory; •the effectiveness of PGE’s risk management policies and procedures; •cybersecurity attacks, data security breaches, physical attacks and security breaches, or other malicious acts that cause damage to the Company’s generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, vendor, employee, or Company information; •employee workforce factors, including potential strikes, work stoppages, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries since the beginning of the COVID-19 pandemic; •new federal, state, and local laws that could have adverse effects on operating results; •failure to achieve the Company’s greenhouse gas emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively respond to legislative requirements concerning greenhouse gas emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation; •social attitudes regarding the electric utility and power industries; •political and economic conditions; •the impact of widespread health developments, 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; •risks and uncertainties related to current or future All-Source RFP projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of tariffs impacting solar module imports), permitting and construction delays, and legislative uncertainty; and •acts of war or terrorism. Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Overview Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC. 41 Table of Contents PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State. The Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. In addition, PGE continues to develop 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 imperatives: •Decarbonize Power—Reduce greenhouse gas (GHG) emissions associated with electricity served to retail customers by at least 80% by 2030 and 100% by 2040; •Electrify the Economy—Increase beneficial electricity use to capture the benefits of new technologies while building an increasingly clean, flexible and reliable grid; and •Advance Performance—Improve safety, efficiency, and system and equipment reliability while maintaining affordable energy service and growing earnings per share 5% to 7% annually. Climate Change State-mandated GHG emissions reduction targets—In June 2021, the Oregon legislature passed House Bill (HB) 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the State. A number of provisions in the bill align with PGE’s strategic direction, and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG emissions reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the Laws and Regulations section of this Overview. Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 233 thousand residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have similar goals and continue to consider similar goals for the future. The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows large business and municipality customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy either from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions. 42 Table of Contents As of December 31, 2023, the Green Future Impact Program has an approved capacity of 750 MW nameplate. Through this voluntary program, the Company seeks to support the customers’ clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power. The Climate Pledge—In 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report GHG emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets. Severe weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. On January 13, 2024, the Company’s service territory encountered the first of a series of severe winter weather events, including snow, ice, and high winds that caused catastrophic damage to physical assets and resulted in widespread customer power outages. For more information regarding the January 2024 severe winter weather events, see “Declared States of Emergency” within this Overview section of this Item 7. August 2023 experienced a record-breaking heat wave with temperatures in the region reaching all-time recorded highs for the month. This resulted in a peak load demand of 4,498 MW, beating the Company’s previous all-time peak load demand, and surpassing the prior summer peak load by nearly 6%. The increase and severity of extreme weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid. Investing in a Clean Energy Future 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 HB 2021, PGE created a Clean Energy Plan (CEP), which articulates the Company’s strategy to meet the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was filed in connection with, the Company’s 2023 IRP. PGE filed its first combined IRP and CEP with the OPUC on March 31, 2023. That filing projects PGE’s resource and capacity needs over the next 20 years and proposes an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements. Throughout the remainder of 2023, PGE refreshed its forecasts, first in an Addendum filed July 7, 2023 then several times in subsequent comments in the CEP and IRP docket with the OPUC (LC 80). PGE currently estimates a total resource need of approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to meet the Company’s 2030 emissions reduction target. Through the 2021 All-Source RFP, PGE procured 311 MW of wind resources and 475 MW of capacity, leaving a remaining need to procure approximately 2,700 to 3,700 MW. On January 25, 2024, the OPUC acknowledged PGE’s IRP, subject to certain conditions, providing regulatory support for the Company to pursue the near-term resource additions articulated in the Action Plan. However, the OPUC declined to acknowledge the CEP, directing the Company to provide additional forecast of its emission reductions based on new analysis in the CEP/IRP Update to be filed in January 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP. 2021 All- Source RFP In 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, to fill the need identified in the 2019 IRP action plan and to meet a portion of the Company’s estimated 2030 need. 43 Table of Contents Pursuant to the 2021 All-Source RFP process, PGE has entered into agreements to acquire the following: •Clearwater Wind Development—PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. entered into agreements to construct a 311 MW wind energy facility, which will be part of the larger Clearwater Wind Development in Eastern Montana. PGE will own 208 MW of production capacity of the 311 MW in these agreements, with an initial expected investment of approximately $415 million, excluding an allowance for funds used during construction (AFUDC). Subsidiaries of NextEra Energy Resources, LLC will own the remaining 103 MW of production capacity and will sell their portion of the output to PGE under a 30-year PPA. Subsidiaries of NextEra Energy Resources, LLC were to design, build, and operate the facility. As of December 31, 2023, the Company has recorded $411 million, including AFUDC, in construction work-in-progress related to Clearwater. Substantial completion of the project was achieved on January 5, 2024 at a placed-in-service cost of $419 million, with $6 million in expected trailing costs remaining. •Seaside Grid—PGE entered into an agreement to construct a 200 MW Battery Energy Storage System (BESS) in Portland, Oregon. PGE will own the resource, with an investment of approximately $360 million, excluding AFUDC. The project has an estimated commercial operation date of June 30, 2025. •Constable BESS—PGE entered into an agreement to construct a 75 MW BESS in Hillsboro, Oregon. PGE will own the resource, with an investment of approximately $150 million, excluding AFUDC. The project has an estimated commercial operation date of December 31, 2024. •Troutdale Grid—PGE entered into a storage capacity agreement for a 200 MW BESS in Troutdale, Oregon. NextEra Energy Resources, LLC will own the resource and will sell the capacity to PGE under a 20-year storage capacity agreement. The project has an estimated commercial operation date of December 31, 2024. The Clearwater agreements and all BESS agreements represent the final procurement from the 2021 All-Source RFP. Resources required to meet the remaining 2030 need are anticipated to be procured through future acquisition processes, including, but not limited to, the 2023 All-Source RFP and future RFPs. All BESS projects will be directly interconnected to PGE’s system. Energy discharge of BESS projects is reflective of the emission characteristics of the energy utilized to charge the facility. BESS projects do not add incremental emissions to the grid, and therefore, are non-emitting dispatchable capacity resources. The BESS agreements will qualify for the federal investment tax credit (ITC). The Clearwater agreements will qualify for PTCs and will be eligible under Oregon’s RPS. The agreements will be subject to prudency review by the OPUC. In February 2022, NewSun Energy LLC (NewSun) filed a petition for judicial review in the Marion County Circuit Court against the OPUC, challenging the scoring methodology in the 2021 All-Source RFP. PGE joined in the case as an intervenor. NewSun also filed a motion to stay the 2021 All-Source RFP process, which the Court subsequently denied. The OPUC filed a motion to dismiss the case and PGE joined the OPUC’s motion to dismiss. NewSun opposed the motion. In May 2022, the Court granted the motion to dismiss to which NewSun responded in June 2022 by filing a notice of appeal with the Court of Appeals of the State of Oregon. After receiving multiple extensions, NewSun filed its opening brief in the appeal in February 2023 and PGE filed a response brief on June 1, 2023. On August 1, 2023, PGE filed a notice asking the Court to dismiss the case. That motion remains pending. Oral argument in this case is scheduled for March 18, 2024. In October 2022, NewSun filed a petition in Deschutes County Circuit Court seeking review of the OPUC order acknowledging, with conditions, PGE’s 2021 All-Source RFP shortlist. PGE intervened in this case and, on March 16, 2023, filed a motion to dismiss. On September 7, 2023, the judge granted PGE’s motion to dismiss. On November 19, 2023, NewSun filed a notice of appeal in the Court of Appeals of the State of Oregon. PGE cannot predict the outcome of these proceedings or potential impact, if any, to its ongoing 2021 All-Source RFP process. 44 Table of Contents 2023 All-Source RFP PGE filed notice with the OPUC on January 31, 2023 that an RFP in 2023 was needed to procure resources to meet a forecasted 2026 capacity shortfall and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan and CEP. The filing included PGE’s request for a partial waiver of the OPUC’s competitive bidding rules, which was approved by the OPUC on April 18, 2023, and outlined PGE’s recommended timeline for obtaining necessary regulatory approvals. PGE filed the draft 2023 All-Source RFP with the OPUC on May 19, 2023 and regulatory approval was granted in January 2024. The Company issued the RFP to market on February 2, 2024, seeking bids for resources that can provide non-emitting dispatchable capacity and renewable generation. The Company will accept and evaluate bids during the first quarter of 2024 and present a shortlist of top-performing projects for OPUC acknowledgement later in the year. Transmission Upgrades In alignment with local and regional transmission plans, the 2023 IRP Action Plan, and CEP, PGE is evaluating and implementing upgrades to existing transmission resources and expansions of current transmission networks. Transmission resource actions are intended to alleviate congestion, improve regional adequacy and reliability, enable decarbonization goals, and address growing customer demand. Building a resilient grid—To serve communities with clean energy, PGE’s grid of the future will need to be smart and adaptive. Highlights of PGE’s key investments and plans for building a resilient grid include: •Wildfire Mitigation—PGE plans and implements a Wildfire Mitigation Program (WMP), developing and coordinating activities across the Company and with state-wide stakeholders. The 2024 WMP forecasts $45 million in operations and maintenance costs and an additional $43 to $49 million in capital investments to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by reducing the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. During 2023, PGE invested $18 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2023 WMP. •Virtual Power Plant (VPP)—PGE’s VPP is a production resource comprised of Distributed Energy Resources (DERs) and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to energy efficiency and flexible load programs, rooftop solar, battery storage, and electric vehicle charging solutions support grid reliability and increase portfolio flexibility and resource diversity. These distributed energy resources are the foundation of PGE’s VPP that will provide a growing suite of grid and system services over time. When coordinated through the Company’s DER Management Systems, DERs and flexible loads support cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. In 2023, PGE saw record energy demand of 4,498 MW on August 14. Customer actions that day, orchestrated through the VPP, reduced load by more than 90 MW, helping avoid customer service interruptions and reducing exposure to scarcity pricing in energy markets. •Distribution System Plan (DSP)—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. The DSP outlines distribution system assets, describes how the Company plans for new load including distributed resources such as electric vehicles (EVs) and Solar Photovoltaic installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in meeting PGE’s clean energy goals. The Company is in the process of compiling the next DSP, which is expected to be filed by the first quarter of 2025. 45 Table of Contents 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 increasing electrification of buildings and supports the accelerating pace of vehicle electrification for our customers, as well as its own vehicle fleet. Transportation electrification is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to manage electric vehicle (EV) charging load, 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 2021, the Oregon legislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification. In 2023, PGE’s second Transportation Electrification (TE) plan was filed and accepted by the OPUC. The TE plan considers current and planned activities, along with EV forecasts and potential system impacts. The 2023 TE plan represents a continuation of the approach and programmatic efforts found within PGE’s 2019 TE plan while also outlining the Company’s current strategy to integrate TE into utility business in order to plan, service, and manage EV load. In the 2023 to 2025 period covered by the 2023 TE plan, capital expenditures are expected to be approximately $25 million. The final 2023 TE plan was accepted by the OPUC on October 17, 2023. In October 2023, the OPUC accepted the planned activities associated with TE. Businesses and families continue to turn to electricity to serve their home and workplace needs. PGE continues to pursue advanced technologies to enhance the grid, pursue distributed generation and energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs. Laws and Regulations Federal Grants—In November 2021, the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA), which includes approximately $550 billion of new federal spending, was signed into law. PGE continues to pursue multiple areas under the IIJA, and other state and federal programs, for potential grant funding of projects. These projects target improvements in electrical system reliability and resiliency, wildfire situational awareness and mitigation, greater communications capabilities, advancements in customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, and regional transmission capacity constraints. As of December 31, 2023, PGE has submitted 16 full federal grant applications and has been awarded eight grants totaling $314.4 million, including the following: •U.S. DOE Bethel-Round Butte Transmission Line Upgrade—The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS), in partnership with PGE, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project will accelerate the development of transmission capacity, enabling new carbon-free generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS Tribal communities by increasing resources available to the Tribes to support adaptation and response strategies. The U.S. DOE and PGE are negotiating the final funding and scope for the line upgrade as part of a multi-year process. •U.S. DOE Smart Grid Chip—The U.S. DOE selected a PGE-led consortium for a $50 million grant for the Smart Grid Chip project. The project will enable real-time information at each meter to improve the visibility of the electrical system to grid operators, providing detection of potential operational problems and shorten outage times, ultimately helping to anticipate and mitigate the impacts of extreme weather on grid resiliency. The DOE and PGE are negotiating the final funding and scope for the project as part of a multi-year process. 46 Table of Contents PGE is in the process of assessing the impacts of these federal grants on the Company’s results of operations. Although PGE continues to apply for additional grants, the Company cannot predict the ultimate timing and success of securing funding from federal programs. Inflation Reduction Act of 2022—The Inflation Reduction Act of 2022 (IRA) was signed into law in August 2022 with a majority of the provisions effective for tax years beginning after December 31, 2022. The United States Treasury and the Internal Revenue Service released extensive rules addressing credit transfer eligibility and application, including but not limited to, required registration, filing, and documentation for transferors and transferees to elect and claim a credit transfer. On December 12, 2023, PGE received approval from the OPUC to transfer 2023 production tax credits and record any difference in the full value and the discounted value in a property balancing account. Consistent with options available under the IRA, PGE sold credits during 2023 and intends to sell credits in the future. Compared to previous resource planning processes, the Company believes the new tax incentives will provide additional investment opportunities for PGE and result in lower customer prices. Increased capital expenditures in such investment opportunities would likely result in additional financing needs through debt and equity instruments. HB 3143—In June 2023, the Oregon Legislature passed HB 3143, which was signed by the Governor on August 1, 2023. HB 3143 allows the OPUC to authorize the State’s investor-owned utilities, including PGE, to issue bonds and securitize debt for expenses associated with declared emergency events. The bill enables PGE, after a public process and rigorous review and approval by the OPUC, to issue, at a minimum, investment grade bonds to pay for the costs of declared emergencies. HB 2021—In June 2021, the Oregon Legislature passed HB 2021, which, among other things, requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. For PGE, the baseline levels are the average annual emissions for the years 2010, 2011, and 2012 associated with the electricity sold to its retail electricity consumers as reported to the Oregon Department of Environmental Quality (ODEQ). HB 2021 requires utilities to develop a CEP for meeting the targets, concurrent with each IRP, and to develop a DSP that establishes reasonable costs for retail electricity consumers. In reviewing a CEP, the OPUC must ensure that utilities plan for equitable implementation, demonstrate continual progress, and take actions as soon as practicable that facilitate rapid reduction of GHG emissions. Regulated entities are required to, and will continue to, report annual GHG emissions to the ODEQ, as they are required to do today. In threshold years, and every year thereafter, the OPUC will use the data reported to the ODEQ for that compliance year to determine whether the reduction targets are met. Utilizing the methodology per the ODEQ’s Greenhouse Gas Reporting Protocol for investor-owned utilities, PGE’s preliminary percentage of 2023 retail load served by non-emitting resources is 32 percent as of December 31, 2023. Governor executive order—In 2020, the Governor of Oregon issued Executive Order 20-04 that directed State agencies to integrate climate change and the State’s GHG emissions reduction goals into their plans, budgets, investments, and decisions to the extent allowed by law. Among other things, Executive Order 20-04, which remains in place until withdrawn or superseded: •directed the OPUC to encourage electric companies to support transportation electrification infrastructure; •directed the ODEQ to adopt a program to cap and reduce GHG emissions within the State from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. In response, in 2021, the ODEQ adopted the Climate Protection Plan, which among various provisions, included an exemption for electricity generation from the Company’s natural gas-fired resources; and •modified the reduction goals of the State’s Clean Fuels Program and extended the program while increasing the required reduction in average carbon intensity of transportation fuels. 47 Table of Contents PGE continues to monitor activities of State agencies that have utilized Executive Order 20-04 to shape State policy or seek to implement it through their own regulatory authority. RPS standards and other laws—In 2016, Oregon Senate Bill (SB) 1547 set a benchmark for the percentage of electricity that must come from renewable sources and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers no later than 2030. PGE ceased coal fired operation at its Boardman generating facility (Boardman) in 2020 and decommissioning of the plant is substantially complete. The Company has a 20% ownership share in Colstrip Units 3 and 4 coal-fired generation plant (Colstrip) and in response to SB 1547, PGE filed a tariff request in 2016 with the OPUC and received approval to accelerate recovery of the Company’s investment in Colstrip from 2042 to 2030. Effective May 9, 2022, PGE’s depreciation rates and associated customer prices changed as approved by the OPUC in the Company’s 2022 General Rate Case (GRC) to reflect further accelerated depreciation of Colstrip from 2030 to December 31, 2025. In order to meet PGE’s regulatory and legislative requirements, the Company continues to evaluate the possibility of exiting ownership in Colstrip. See Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data” for information regarding legal proceedings related to Colstrip. Any reduction in generation from Colstrip has the potential to provide additional capacity availability on the Colstrip transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in the Pacific Northwest and neighboring states. PGE has an approximate 15% ownership interest in, and capacity on, the Colstrip transmission facilities. See “Investing in a Clean Energy Future” in this Overview for information regarding development in eastern Montana. Other provisions of SB 1547: •establish RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040; •limit the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continue unlimited lifespan for all existing RECs and allow for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and •provide opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s RAC filings. For a more comprehensive review of Environmental Matters, see “Environmental Matters” in Item 1.—Business. Regulatory Matters PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on such matters. General Rate Case—In February 2023, PGE filed with the OPUC a GRC based on a 2024 test year (2024 GRC). All items, including NVPC, have been resolved. The OPUC authorized a: •capital structure of 50% debt and 50% equity; •return on equity of 9.5%; and •cost of capital of 6.993%, which reflects updates for actual and forecasted debt costs. 48 Table of Contents The OPUC approved an annual revenue requirement increase of $391 million and an average rate base of $6.2 billion. New customer prices, as approved by the OPUC, became effective January 1, 2024. Key elements of the OPUC’s Orders in the 2024 GRC include: •resolution of all issues concerning recovery of costs included in the 2024 GRC for the Faraday Resiliency and Repowering Project; •provision, which will sunset after December 31, 2025, to recover 80% of costs for Reliability Contingency Events (RCE), as defined in the settlement, above amounts forecasted in the AUT without application of an earnings test, and allowance for the remaining 20% to flow through the existing PCAM; •establishment of a balancing account that will sunset after December 31, 2026, for recovery of routine vegetation management expenses; and •authorization of a tariff filing, which the Company submitted to the OPUC on January 26, 2024, that proposes for residential and small non-residential customers weather-normalized decoupling that would sunset after December 31, 2025. Complete details of the 2024 GRC (OPUC Docket UE 416) is available on the OPUC Internet website at www.oregon.gov/puc. COVID-19 impacts—In March 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. PGE’s deferral application was approved by the OPUC in October 2020 with final stipulations for the Term Sheet approved in November 2020. As of December 31, 2023 and December 31, 2022, PGE’s deferred balance was $14 million and $22 million, respectively, comprised primarily of bad debt expense in excess of what was collected in customer prices. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. On March 21, 2023, Advice No. 22-45 was approved by the OPUC, allowing for amortization of deferred amounts over a two-year period beginning April 1, 2023. Wildfire mitigation—Under SB 762, enacted in July 2021, PGE encountered incremental costs and investments related to intensifying efforts on its system to mitigate the risk of wildfire and improve resiliency to wildfire damage. These efforts include enhanced tree and brush clearing, hardening equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. Pursuant to SB 762, PGE submitted its 2023 risk-based Wildfire Mitigation Plan to the OPUC in December 2022 and it was approved in Order 23-221 on June 26, 2023. As of December 31, 2023 and December 31, 2022, PGE’s deferred balance related to wildfire mitigation, net of amortization, was $29 million and $28 million, respectively. The 2023 balance is comprised of: •Base Rates - The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in base rates in regard to wildfire mitigation efforts beginning May 9, 2022. As of December 31, 2023, there was $1 million in the balancing account. •Previously Deferred - Prior to establishing the base rates collection noted above, PGE had deferred incremental costs related to wildfire mitigation and as of December 31, 2023 this balance is $28 million. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs that exceed the amount granted in base rates. On May 10, 2023, in Order No. 23-173, the OPUC approved an automatic adjustment clause mechanism to recover wildfire mitigation costs (capital and expense). PGE and certain parties agreed to a stipulation, which was adopted by the OPUC on October 18, 2023, that allows PGE to begin amortizing $27 million comprised of $23 million related to the September 30, 2023 deferred operating expense balance of $31 million and $4 million for capital related revenue requirement. 49 Table of Contents Beginning January 1, 2024, PGE will remove collections related to wildfire mitigation costs (for both capital and expense) from base prices and include the forecasted costs within the automatic adjustment clause in a separate tariff to begin April 1, 2024. Differences between actual and forecasted costs will be recorded as regulatory assets or liabilities within the automatic adjustment clause balancing account, which will not be subject to an earnings test. Declared states of emergency—In September 2021, the OPUC issued an order that approved a pre-authorized deferral of costs associated with declared states of emergency. Qualifying events would include federal or state declared emergencies with impacts on PGE’s service territory. Previously the Company had to file a request for deferred accounting when an event of that nature occurred, and had to seek OPUC approval of such deferred accounting applications to be effective. With this order, PGE would provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including a review of utility prudence in a future proceeding, among other requirements. As of December 31, 2023, PGE had not recorded any costs under this deferral order. Beginning January 13, 2024, the Company’s service territory encountered a severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to physical assets and resulted in widespread customer power outages. Along with over a dozen mutual assistance crews, PGE repaired damage and restored power to over 500,000 customers throughout the storm and the days that followed. PGE currently estimates the incremental incurred and future costs to repair damage to PGE’s transmission and distribution systems and restore power to customers could range from $50 million to $60 million, with $35 million to $45 million of that range estimated to represent operating expenses associated with transmission and distribution. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which will allow PGE to seek recovery of incremental storm expenses through the previously filed emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC, under Docket UM 2190, related to the emergency restoration costs for the January storm and expects to defer a significant portion of these costs as regulatory assets. Due to the storm and corresponding impact on power markets, PGE has incurred a substantial amount of incremental net variable power costs compared to what was anticipated in the 2024 AUT. PGE believes that a portion of the storm will qualify as a Reliability Contingency Event (RCE) as approved by the OPUC in PGE’s 2024 GRC. Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. Estimates of the total cost for the RCE are still under development, however the Company believes total costs could be in the range of $85 million to $100 million. Full impacts cannot be determined until all settlements and invoices are received for the period to which the RCE applies. PGE expects to defer a significant majority of these costs through its various OPUC approved mechanisms over net variable power costs. PGE believes it has adequate liquidity to cover the event. 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 2023 AUT included a final increase in power costs for 2023, and a corresponding increase in annual revenue requirement of $186 million from 2022 levels, which were reflected in customer prices effective January 1, 2023. The 2024 AUT contains a $216 million increase in NVPC that will be recovered in customer prices beginning January 1, 2024. For more information regarding the PCAM, see “Power operations” within this Overview section of Item 7. Portland Harbor Environmental Remediation Account (PHERA) mechanism—The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor 50 Table of Contents Superfund site. As of December 31, 2023, significant uncertainties still remained concerning the precise requirements for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision (ROD) issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the recovery mechanism allows the Company to defer and recover estimated liabilities and incurred legal and technical analysis expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including, but not limited to, insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE’s results of operations may be impacted to the extent such expenditures were to be deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see “EPA Investigation of Portland Harbor” in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Decoupling—The decoupling mechanism, previously authorized by the OPUC through 2022, was intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provided for collection from (or refund to) customers if weather-adjusted use per customer was less (or more) than that projected in the Company’s most recent GRC. In the 2022 GRC, parties reached an agreement that eliminated PGE’s decoupling mechanism upon the effective date of new customer prices that resulted in May 2022. Pursuant to the 2022 GRC Order, the OPUC adopted the agreement such that deferrals would not occur after 2022, although amortization of then previously recorded deferrals was to continue as scheduled until collected or refunded in future customer prices. For the year ended December 31, 2022, with OPUC approval, PGE is collecting $5 million in customer prices over a one-year period that began January 1, 2024. In the 2024 GRC filing, the Company included a concept proposal that could lead to resuming decoupling, with certain modifications. As stipulated in the 2024 GRC settlement agreement, PGE made a tariff filing, on January 26, 2024, that proposes weather-normalized decoupling, which would begin April 1, 2024 and sunset after December 31, 2025, for residential and small non-residential customers. The proposal seeks a 3% annual limit on collections or refunds and a balancing account, which would carry forward to subsequent years for refund or recovery, to capture any amounts that exceed the limit. Deferral of Boardman revenue requirement—In 2020, intervenors filed a deferral application with the OPUC that would have required PGE to defer and refund the revenue requirement associated with the Company’s Boardman coal-fired generating plant (Boardman) then included in customer prices as established in the Company’s 2019 GRC. Customer prices resulting from the 2022 GRC Order no longer included any revenue requirement related to Boardman after new customer prices took effect on May 9, 2022. The OPUC found that the deferral was warranted with amortization subject to an earnings test. Subsequently, PGE and parties submitted stipulations to the OPUC reflecting agreements that resolved all matters related to this deferral and stated that PGE would refund $6.5 million to customers. On June 5, 2023, the OPUC issued Order 23-195, which approved the stipulations. The refund amount, plus interest, is being amortized into customer prices over a two-year period that began July 1, 2023. 51 Table of Contents Renewable recovery framework—As previously authorized by the OPUC, the RAC is a primary method available to recover costs associated with renewable resources. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a GRC. Under the RAC, during 2023, the Company submitted a filing for Clearwater that went into service January 5, 2024. PGE estimates the requested tariff, to begin June 1, 2024, will result in an overall $28 million reduction in annual revenues, which results from customer credits. The Company plans to defer the revenue requirement between January 5, 2024 and May 31, 2024 for consideration in a future regulatory proceeding. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. Operating Activities In addition to electricity provided by PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, manage risk, and administer its long-term wholesale contracts, the Company purchases and sells electricity in the wholesale market. PGE also performs portfolio management and wholesale market sales services for third parties in the region. The Company participates in the western EIM, which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. The Company also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market. PGE generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers in Oregon. 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 had experienced its highest MWa deliveries and retail energy sales during the winter heating season and recorded its current winter peak load in December 2022. Summer peak deliveries have continued to exceed those of the winter months for several years, generally resulting from air conditioning demand and the trend toward a warmer overall climate. During the summer of 2023, demand reached a new all-time high, surpassing the previous mark, which was set in 2021. For further information regarding seasonal fluctuations, see “Seasonality” in the Customers and Revenues section in Item 1.—“Business.” Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal plants can also affect income from operations. PGE has taken measures to enhance the availability of supply chain-constrained items that are needed to serve new and existing customers, such as advance ordering of critical materials, pre-securing manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. PGE has also taken measures to help mitigate cost increases through long term agreements, supplier engagement and expanding the supply base. Customers and demand—The following tables present total energy deliveries and the average number of retail customers by type for 2023 and 2022. 52 Table of Contents [[GREPCENT_TABLE]] [["Energy deliveries (MWh in thousands)","","","2023","","","","2022","","% Increase/ (Decrease)"],["Retail:"],["Residential","","","7,952","","","","","8,088","","","(1.7)","%"],["Commercial (PGE sales only)","","","6,601","","","","","6,650","","","(0.7)"],["Direct Access","","","577","","","","","548","","","5.3"],["Total Commercial","","","7,178","","","","","7,198","","","(0.3)"],["Industrial (PGE sales only)","","","4,578","","","","","4,167","","","9.9"],["Direct Access","","","1,715","","","","","1,778","","","(3.5)"],["Total Industrial","","","6,293","","","","","5,945","","","5.9"],["Total (PGE sales only)","","","19,131","","","","","18,905","","","1.2"],["Total Direct Access","","","2,292","","","","","2,326","","","(1.5)"],["Total retail energy deliveries","","","21,423","","","","","21,231","","","0.9","%"],["Wholesale energy deliveries","","","6,950","","","","","6,000","","","15.8"],["Total energy deliveries","","","28,373","","","","","27,231","","","4.2","%"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["Average number of retail customers","","2023","","2022","","% Increase/ (Decrease)"],["Residential","","815,920","","","88","%","","809,573","","","88","%","","0.8","%"],["Commercial","","112,204","","","12","","","112,127","","","12","","","0.1"],["Industrial","","196","","","\u2014","","","192","","","\u2014","","","2.1"],["Direct access","","540","","","\u2014","","","552","","","\u2014","","","(2.2)"],["Total","","928,860","","","100","%","","922,444","","","100","%","","0.7","%"]] [[/GREPCENT_TABLE]] In 2023, retail energy deliveries increased 0.9% from 2022, with increases in demand from industrial customers outweighing the decreases seen in the residential and commercial classes. The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Compared to the prior year, weather had a negative impact on deliveries, as warm weather in the fourth quarter more than offset cooler temperatures early in the year. In 2022, PGE began to see decreases in average residential usage on a weather-adjusted, year over year basis, however expects that the shift that has occurred with respect to hybrid work schedules will have lasting impacts on average usage. Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 1.7% lower in 2023 than 2022, due to a 2.5% decrease in average usage per customer, which resulted largely from warmer fourth quarter temperatures, and was partially offset by an 0.8% increase in the average number of customers. Commercial energy deliveries were fairly stable in 2023 with the prior year, showing a decrease of 0.3%. While COVID-19 related recovery has largely occurred, continued impacts of programmatic energy efficiency and uncertainty in economic conditions have tempered commercial growth in 2023. Industrial energy deliveries increased 5.9% in 2023 due to continued strength in the high-tech manufacturing and digital service sector. Several large customers experienced continued growth in 2023 and new data center facilities came online. Total heating degree-days, an indication of electricity use for heating, declined 6% in 2023 from 2022 in total, and was 6% below the 15-year moving average. However, while 2023 began with low temperatures and high seasonal heating demand, that pattern reversed in the second quarter as heating degree-days fell below prior year and seasonal averages. Correspondingly, cooling degree-days, a similar indication of the extent to which customers were 53 Table of Contents likely to have used electricity for cooling, exceeded the 15-year average by 50%, although were only 4% above the 2022 total, illustrating that the two most recent summer seasons have been exceedingly warm compared to historical averages. The Company experienced a new record winter peak load in December 2022 of 4,113 MW and a new summer peak in August 2023 of 4,498 MW. The warm temperatures persisted through the balance of the year, with actual temperatures in the fourth quarter, which is normally a high heating demand period, being among the warmest ever recorded. The following table presents the number of heating and cooling degree-days in 2023 and 2022, along with the current 15-year averages, reflecting the influence that weather had on comparative energy deliveries. [[GREPCENT_TABLE]] [["","Heating Degree-Days","","Cooling Degree-Days"],["","2023","","2022","","15-Year Average","","2023","","2022","","15-Year Average"],["1st quarter","1,927","","","1,761","","","1,840","","","\u2014","","","\u2014","","","\u2014"],["2nd quarter","554","","","760","","","628","","","195","","","75","","","101"],["3rd quarter","45","","","6","","","65","","","687","","","745","","","493"],["4th quarter","1,319","","","1,576","","","1,552","","","16","","","45","","","5"],["Total","3,845","","","4,103","","","4,085","","","898","","","865","","","599"],["Increase (decrease) from the 15-year average","(6)","%","","\u2014","%","","","","50","%","","44","%"]] [[/GREPCENT_TABLE]] On a weather-adjusted basis, total retail deliveries increased 1.4 % from 2022. The increase was driven by a 5.9% growth in industrial deliveries, partially offset by a 0.2% decline in commercial energy deliveries and a 0.5% decrease in weather-adjusted deliveries to residential customers, as average use per customer has declined from the highs seen during the first two years of the COVID-19 pandemic. The Company projects that retail energy deliveries for 2024 will be between 2% and 3% above 2023 weather-adjusted levels, reflecting continued growth in industrial deliveries. ESSs supplied Direct Access customers with energy representing 11% of PGE’s total retail energy deliveries during 2023 and 2022. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 12% of the Company’s total retail energy deliveries for 2023. With the adoption of the New Large Load Direct Access program in 2020, as much as 17% of the Company’s 2023 energy deliveries could have been supplied by ESSs. Power operations—PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period and impacts NVPC and income from operations. The following table provides information regarding the performance of the Company’s generation portfolio. 54 Table of Contents [[GREPCENT_TABLE]] [["","Plant availability (1)","","Actual energy provided compared to projected levels (2)","","Actual energy provided as a percentage of total retail load"],["","2023","2022","","","2023","2022","","2023","2022"],["Thermal:"],["Natural gas","85","%","86","%","","","99","%","81","%","","54","%","41","%"],["Coal (3)","90","","89","","","","99","","100","","","11","","11"],["Wind (4)","98","","82","","","","88","","81","","","9","","9"],["Hydro","89","","94","","","","69","","81","","","6","","5"]] [[/GREPCENT_TABLE]] (1)Plant availability represents the percentage of the year plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2)Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources. (3)Plant availability reflects Colstrip, which PGE does not operate. (4)Plant availability includes Wheatridge, which PGE does not operate. Energy received from PGE-owned and jointly-owned thermal plants in 2023 compared to 2022 increased by 27%. This increase is primarily driven by economic dispatch decisions and to replace shortfalls from hydro and wind resources. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year. Total energy received from all hydroelectric sources, both PGE-owned generation and purchased, decreased 21% in 2023 compared to 2022 primarily due to less favorable hydro conditions in the current period. Energy purchased from mid-Columbia and other regional hydroelectric projects decreased 26% while energy generated by the Company-owned facilities increased 11% in 2023. 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. For further detail on regional hydro results, see “Purchased power and fuel” in the Results of Operations section in this Item 7. Energy received from PGE-owned wind resources and under contracts increased 7% in 2023 compared to 2022. While 2023 saw less favorable wind conditions, unplanned plant outages in 2022 that did not reoccur resulted in the overall net increase year over year. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for 2023 and 2022: •For 2023, actual NVPC was above baseline NVPC by $5 million, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2023. A final determination regarding the 2023 PCAM results will be made by the OPUC through a public filing and review in 2024. 55 Table of Contents •For 2022, actual NVPC was above baseline NVPC by $23 million, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded as of December 31, 2022. Results of Operations The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations. The results of operations are as follows for the years presented (dollars in millions): [[GREPCENT_TABLE]] [["","Years Ended December 31,","","% Increase (Decrease)"],["","2023","","2022"],["","Amount","","Amount"],["Total revenues","$","2,923","","","$","2,647","","","10","%"],["Operating expenses:"],["Purchased power and fuel","1,190","","","988","","","20"],["Generation, transmission and distribution","374","","","348","","","7"],["Administrative and other","341","","","340","","","\u2014"],["Depreciation and amortization","458","","","417","","","10"],["Taxes other than income taxes","164","","","157","","","4"],["Total operating expenses","2,527","","","2,250","","","12"],["Income from operations","396","","","397","","","\u2014"],["Interest expense, net *","173","","","156","","","11"],["Other income:"],["Allowance for equity funds used during construction","19","","","14","","","36"],["Miscellaneous income, net","31","","","17","","","82"],["Other income, net","50","","","31","","","61"],["Income before income taxes","273","","","272","","","\u2014"],["Income tax expense","45","","","39","","","15"],["Net income","$","228","","","$","233","","","(2)","%"]] [[/GREPCENT_TABLE]] * Includes an allowance for borrowed funds used during construction of $13 million in 2023 and $7 million in 2022. 2023 Compared to 2022 Net income for 2023 decreased $5 million from 2022. In 2023, higher Purchased power and fuel costs more than offset increases in Retail revenues authorized by the OPUC in the AUT in anticipation of higher NVPC. Retail revenues also increased due to an overall increase in deliveries, although that demand impact was more than offset by the average price result of the relative mix of deliveries among customer classes. Warm temperatures in the latter portion of 2023 suppressed demand from residential customers while the industrial class continued to show strength. The impact of higher natural gas and electricity prices coupled with increased customer demand added upward pressure on Purchased power and fuel expense. Wholesale sales increased, driven largely by economic dispatch decisions and portfolio positions, which contributed to reducing NVPC. Operating expenses reflect the additional charges that resulted from the amortization of prior deferrals, vegetation management and wildfire mitigation efforts, and increased run hours at generation facilities in 2023.The increase in Depreciation and amortization reflect higher utility plant balances and charges resulting from prior regulatory deferrals. Interest expense rose primarily due to higher long-term debt and outstanding commercial paper balances. Other income was up due to favorable market changes on the non-qualified benefit trust, higher AFUDC equity income driven by higher construction work-in-progress balances in 2023, the recognition of previously deferred equity interest income 56 Table of Contents in conjunction with amortization of regulatory deferrals that began in 2023, and higher other regulatory interest income, all of which was partially offset by a prior year settlement gain on a benefit plan. Total revenues consist of the following for the years presented (in millions): [[GREPCENT_TABLE]] [["","2023","","2022","","% Increase (Decrease)"],["Retail:"],["Residential","$","1,263","","","$","1,158","","","9","%"],["Commercial","800","","","723","","","11"],["Industrial","349","","","289","","","21"],["Subtotal","2,412","","","2,170","","","11"],["Direct Access:"],["Commercial","8","","","12","","","(33)"],["Industrial","19","","","23","","","(17)"],["Subtotal","27","","","35","","","(23)"],["Subtotal Retail","2,439","","","2,205","","","11"],["Alternative revenue programs, net of amortization","11","","","11","","","\u2014"],["Other accrued (deferred) revenues, net","(3)","","","7","","","(143)"],["Total retail revenues","2,447","","","2,223","","","10"],["Wholesale revenues","418","","","363","","","15"],["Other operating revenues","58","","","61","","","(5)"],["Total revenues","$","2,923","","","$","2,647","","","10","%"]] [[/GREPCENT_TABLE]] 57 Table of Contents Total retail revenues—The following items contributed to the increase in Total retail revenues for the year ended December 31, 2023 compared to the year ended December 31, 2022 (dollars in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","2,223"],["Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)","186"],["Recovery of deferrals for 2020 Labor Day wildfire and 2021 ice storm","26"],["Retail energy deliveries driven by changes in customer load","18"],["PCAM collection, offset in Purchased power and fuel expense","14"],["Wildfire mitigation revenue (offset in Generation, transmission and distribution)","12"],["Colstrip depreciation life adjustment (offset in Depreciation and amortization expense)","9"],["Boardman settlement refund, net of amortization","(5)"],["Average price of energy deliveries due primarily to the relative mix of deliveries among customer classes","(44)"],["Combination of various supplemental tariffs and adjustments","8"],["Year ended December 31, 2023","2,447"],["Change in Total retail revenues","$","224"]] [[/GREPCENT_TABLE]] Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company’s efforts to meet the needs of, and secure reasonably priced power for, its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. In 2023, a $55 million, or 15%, increase from 2022 in wholesale revenues occurred as sales volumes increased 16%, which resulted in a $57 million increase. Partly offsetting that increase was a $2 million decrease in average prices received when the Company sold power into the wholesale market. Elevated sales prices continued during 2023 and have resulted from several factors, including reduced hydro generation in the region, the economic recovery, strong demand, and ongoing capacity limitations in the region. Other operating revenues decreased $3 million, or 5%, in 2023 from 2022, primarily as a result of market conditions in 2022 that allowed the Company to sell natural gas in excess of amounts needed for the Company’s generation portfolio back into the wholesale market at gains that have exceeded those experienced during 2023. Purchased power and fuel expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. 58 Table of Contents The following items contributed to the increase in Purchased power and fuel for the year ended December 31, 2023 compared to the year ended December 31, 2022 (dollars in millions, except for average variable power cost per MWh): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","988"],["Average variable power cost per MWh","278"],["Total system load","(91)"],["2021 PCAM deferral amortization","15"],["Year ended December 31, 2023","1,190"],["Change in Purchased power and fuel","$","202"],["Average variable power cost per MWh:"],["Year ended December 31, 2022","$","37.71"],["Year ended December 31, 2023","$","43.26"],["Total system load (MWh in thousands):"],["Year ended December 31, 2022","26,215"],["Year ended December 31, 2023","27,169"]] [[/GREPCENT_TABLE]] For the year ended December 31, 2023, the $278 million increase related to the change in average variable power cost per MWh was primarily driven by a 17% increase in the average cost for purchased power, and a 77% increase in the average cost of power from the Company’s own generation, driven primarily by the settlement of physical and financial gas contracts. The $91 million decrease related to total system load was primarily due to the change in mix of sources of energy with purchased power declining 16% resulting in a $131 million decrease, offset by a 23% increase in energy obtained from PGE’s own generation resulting in a $40 million increase. PGE’s sources of energy, total system load, and retail load requirement for the years presented are as follows: [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2023","","2022"],["Sources of energy (MWh in thousands):"],["Generation:"],["Thermal:"],["Natural gas","10,981","","","40","%","","8,242","","","31","%"],["Coal","2,214","","","8","","","2,186","","","8"],["Total thermal","13,195","","","48","","","10,428","","","39"],["Hydro","1,144","","","4","","","1,027","","","4"],["Wind","1,918","","","7","","","1,765","","","7"],["Total generation","16,257","","","59","","","13,220","","","50"],["Purchased power:"],["Hydro","4,646","","","17","","","6,297","","","24"],["Wind","846","","","3","","","824","","","3"],["Solar","1,055","","","4","","","723","","","3"],["Natural Gas","184","","","1","","","33","","","\u2014"],["Waste, Wood and Landfill Gas","163","","","1","","","168","","","1"],["Source not specified","4,018","","","15","","","4,961","","","19"],["Total purchased power","10,912","","","41","","","13,006","","","50"],["Total system load","27,169","","","100","%","","26,226","","","100","%"],["Less: wholesale sales","(6,950)","","","","","(6,000)"],["Retail load requirement","20,219","","","","","20,226"]] [[/GREPCENT_TABLE]] 59 Table of Contents Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows: [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2023","","2022"],["Sources of energy (MWhs in thousands):"],["PURPA purchased power:"],["Hydro","28","","","36"],["Wind","25","","","25"],["Solar","592","","","588"],["Waste, Wood, Landfill Gas, and Other","114","","","101"],["Total","759","","","750"]] [[/GREPCENT_TABLE]] The following table presents the forecasted April-to-September 2024 and actual April-to-September 2023 and 2022 runoff at particular points of major rivers relevant to PGE’s hydro resources: [[GREPCENT_TABLE]] [["","Runoff as a Percent of Normal*"],["Location","2024Forecast","","2023Actual","","2022Actual"],["Columbia River at The Dalles, Oregon","81","%","","83","%","","107","%"],["Mid-Columbia River at Grand Coulee, Washington","79","","","79","","","110"],["Clackamas River at Estacada, Oregon","92","","","101","","","139"],["Deschutes River at Moody, Oregon","99","","","98","","","92"]] [[/GREPCENT_TABLE]] * Volumetric water supply forecasts and historical averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center, with the Natural Resources Conservation Service and other cooperating agencies. Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $147 million in 2023 compared with 2022. The increase attributable to changes in Purchased power and fuel expense was the result of a 15% increase in the average variable power cost per MWh and a 4% increase in total system load. The increase in actual NVPC was also a result of the 1% lower average price per MWh sold and a 16% increase in the volume of wholesale energy deliveries. The following items contributed to the increase in Actual NVPC for the year ended December 31, 2023 compared to the year ended December 31, 2022 (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","626"],["Purchased power and fuel expense","187"],["Wholesale revenues","(55)"],["2021 PCAM deferral amortization","15"],["Year ended December 31, 2023","773"],["Change in NVPC","$","147"]] [[/GREPCENT_TABLE]] For further information regarding NVPC in relation to the PCAM, see “Power operations” in the Overview section of this Item 7. 60 Table of Contents Generation, transmission and distribution expense increased $26 million or 7% for the year ended December 31, 2023 compared to the year ended December 31, 2022, with the change attributed largely to the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","348"],["Amortizations of previously deferred 2020 wildfire and 2021 ice storm costs","18"],["Higher vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses","15"],["Increase in generation facility maintenance expenses driven by major maintenance activities and increased run hours","13"],["Lower service restoration and storm response costs","(7)"],["Release of deferred amounts pursuant to earnings test in 2022","(16)"],["Miscellaneous expenses","3"],["Year ended December 31, 2023","374"],["Change in Generation, transmission and distribution","$","26"]] [[/GREPCENT_TABLE]] Administrative and other expense increased $1 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 due largely to the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","340"],["Amortization of COVID-19 bad debt expense deferral","9"],["Regulatory program amortization","3"],["Lower employee compensation and benefits expenses","(4)"],["Lower professional service expenses","(8)"],["Miscellaneous expenses","1"],["Year ended December 31, 2023","341"],["Change in Administrative and other","$","1"]] [[/GREPCENT_TABLE]] PGE commenced amortization of previously deferred COVID-19 related bad debt expenses on April 1, 2023. PGE amortized $9 million of COVID-19 related bad debt expense for the twelve months ended December 31, 2023. See Note 7, Regulatory Assets and Liabilities, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements,” for more information. Depreciation and amortization expense increased $41 million or 10% for the year ended December 31, 2023 compared to year ended December 31, 2022, with the change largely resulting from the following items (in millions): [[GREPCENT_TABLE]] [["Year ended December 31, 2022","$","417"],["Capital additions","20"],["Activity related to regulatory programs (offset elsewhere on the income statement)","13"],["Accelerated depreciation of the Colstrip facility as approved by the OPUC\u2019s 2022 GRC Order","9"],["Miscellaneous expenses","(1)"],["Year ended December 31, 2023","458"],["Change in Depreciation and amortization","$","41"]] [[/GREPCENT_TABLE]] Taxes other than income taxes expense increased $7 million, or 4%, in 2023 compared with 2022, primarily due to higher franchise fees and property tax expenses. 61 Table of Contents Interest expense increased $17 million, or 11%, in 2023 compared with 2022 driven by higher average balances of outstanding debt, partially offset by higher AFUDC debt income driven by higher construction work-in-progress balances in 2023. Other income, net increased $19 million, or 61%, in 2023 compared to 2022. The increase was primarily attributable to $11 million in favorable market changes on the non-qualified benefit trust, $11 million in higher regulatory interest income, and $6 million higher AFUDC equity income driven by higher construction work-in-progress balances in 2023. The increase was partially offset by the execution of a buyout of the Non-represented Retiree Medical Plan in 2022, resulting in a $11 million settlement gain. For more information, see Note 11, Employee Benefits, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplemental Data.” Income tax expense increased $6 million, or 15%, in 2023 compared to 2022 primarily driven by lower research and development tax credit benefits. The increase was partially offset by lower expenses from flow-through items. 2022 Compared to 2021 For a comparison of the Company’s results of operations for the fiscal year ended December 31, 2022 to the year ended December 31, 2021, see Item 7.—” Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 16, 2023. Liquidity and Capital Resources Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE’s assumptions regarding the availability and cost of capital. See “Capital and credit market conditions could adversely affect the Company’s access to capital, cost of capital, and ability to execute its strategic plan.” in Item 1A.—“Risk Factors,” for further information. Capital Requirements The following table presents actual capital expenditures and debt maturities for 2023 and projected capital expenditures and future debt maturities for 2024 through 2028 (in millions, excluding AFUDC): [[GREPCENT_TABLE]] [["","Years Ending December 31,"],["","2023","","2024","","2025","","2026","","2027","","2028"],["Ongoing capital expenditures (1)","$","792","","","$","895","","","$","865","","","$","895","","","$","890","","","$","920"],["Transmission","144","","","170","","","180","","","255","","","265","","","435"],["Clearwater Wind Development","$","405","","","$","10","","","$","\u2014","","","$","\u2014","","","$","\u2014","","","$","\u2014"],["BESS projects","$","121","","","$","235","","","$","155","","","$","\u2014","","","$","\u2014","","","$","\u2014"],["Total capital expenditures (2)","$","1,462","","","$","1,310","","","$","1,200","","","$","1,150","","","$","1,155","","","$","1,355"],["Long-term debt maturities","$","260","","","$","80","","","$","\u2014","","","$","\u2014","","","$","160","","","$","100"]] [[/GREPCENT_TABLE]] (1) Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects. Includes accrued capital additions, preliminary engineering, removal costs, and certain intangible working capital assets. (2) Amounts subsequent to 2023 are estimates as of the date of this report and may be affected by economic conditions, including but not limited to, impacts of inflation, changes to the cost of materials and labor, and financing costs. 62 Table of Contents During 2023, PGE funded its capital expenditures through a combination of cash from operations in the amount of $420 million, proceeds from the issuance of FMBs in the total amount of $600 million, and net proceeds from the issuance of shares pursuant to the equity forward sale agreement (EFSA) of $485 million. Capital expenditures in 2024 are expected to be approximately $1.3 billion. PGE plans to fund the 2024 capital expenditures with cash from operations during 2024, which is expected to range from $700 million to $800 million, the issuance of debt securities of up to $730 million, issuances of shares pursuant to the at the market offering program, and the issuance of commercial paper, as needed. The actual timing and amount of any other issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7. Liquidity PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves. The following summarizes PGE’s cash flows for the periods presented (in millions): [[GREPCENT_TABLE]] [["","Years Ended December 31,"],["","2023","","2022"],["Cash and cash equivalents, beginning of year","$","165","","","$","52"],["Net cash provided by (used in):"],["Operating activities","420","","","674"],["Investing activities","(1,358)","","","(758)"],["Financing activities","778","","","197"],["Net change in cash and cash equivalents","(160)","","","113"],["Cash and cash equivalents, end of year","$","5","","","$","165"]] [[/GREPCENT_TABLE]] 2023 Compared to 2022 Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for 2023 compared to 2022 (dollars in millions): [[GREPCENT_TABLE]] [["","Increase/ (Decrease)"],["Net income","$","(5)"],["Accounts receivable and unbilled revenue","37"],["Margin deposit activity","(113)"],["Accounts payable","(323)"],["Regulatory deferral activity","85"],["Depreciation and amortization","41"],["Proceeds from tax credit sales","24"],["Net change in cash flow from operations","$","(254)"]] [[/GREPCENT_TABLE]] 63 Table of Contents For the year ended December 31, 2023, operating cash flows were significantly impacted by changes in working capital from December 31, 2022, primarily related to Accounts payable for purchased power and fuel costs and related margin deposits activity. In December 2022, PGE experienced elevated natural gas and power prices due to volatility in the wholesale markets, which led to increased cash used in operating activities for 2023 as cash payments for physical commodity purchases and related margin activity were made. For additional information regarding changes in Net income, see the Results of Operations section in this Item 7. Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 2024 will range from $475 million to $525 million. Combined with all other sources, cash provided by operations in 2024 is estimated to range from $700 million to $800 million. Cash provided by operations includes the recovery in customer prices of cash charges related to various long-term contractual obligations such as interest on long-term debt and purchased power and fuel contracts. PGE’s anticipated employer contributions for its defined benefit pension plan and other postretirement plans is $29 million in 2024, $24 million in 2025, 2026, and in 2027, and $23 million in 2028. Contributions are expected to be covered by cash provided by operations. For additional information regarding contractual obligations, see Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation, transmission, and distribution facilities. The $600 million increase in net cash used in investing activities in 2023 compared with 2022 is primarily due to capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $592 million due primarily to the Clearwater Wind and BESS projects, as well as an $11 million increase related to proceeds from the sale of property in 2022 that did not recur. The Company plans for $1.3 billion of capital expenditures in 2024 related to upgrades to and replacement of generation, transmission, and distribution infrastructure as well as costs related to BESS projects. PGE plans to fund the 2024 capital expenditures with cash from operations during 2024, as discussed above, as well as with the issuance of debt, issuances of shares pursuant to the at the market offering program, and short-term debt as necessary. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 7. Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2023, cash provided by financing activities was primarily the result of $485 million in proceeds from the issuance of common stock pursuant to the EFSA, funding of $600 million in FMBs, and $146 million due to the issuance of commercial paper. This was partially offset by a $260 million repayment of a term loan and payment of dividends in the amount of $179 million. 2022 Compared to 2021 For a comparison of liquidity and capital resources and the Company’s cash flow activities for the fiscal year ended December 31, 2022 and 2021, see Item 7.—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on February 16, 2023. 64 Table of Contents Credit Ratings and Debt Covenants PGE’s secured and unsecured debt is rated investment grade by Moody’s and S&P, with current credit ratings and outlook as follows: [[GREPCENT_TABLE]] [["","Moody\u2019s","","S&P"],["First Mortgage Bonds","A1","","A"],["Senior unsecured debt","A3","","BBB+"],["Commercial paper","P-2","","A-2"],["Outlook","Stable","","Stable"]] [[/GREPCENT_TABLE]] In the event Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to higher fees on its revolving credit facility. The Company could also be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE’s consolidated balance sheets, while any letters of credit issued are not reflected in the Company’s consolidated balance sheets. As of December 31, 2023, PGE had posted $132 million of collateral with these counterparties, consisting of $92 million in cash and $40 million in bank letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2023, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $76 million and decreases to $60 million by December 31, 2024 and $10 million by December 31, 2025. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade as of December 31, 2023 is $204 million and decreases to $188 million by December 31, 2024 and $82 million by December 31, 2025. PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facilities would increase. The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2023, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $602 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property. PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt to total capital ratio). As of December 31, 2023, the Company’s debt to total capital ratio, as calculated under the credit agreements, was 56.2%. Debt and Equity Financings PGE’s ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, credit ratings, capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to inflationary pressures and 65 Table of Contents interest rate increases by the federal reserve. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future. Short-term Debt—Pursuant to an order issued by the FERC on January 18, 2024, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2026. The following table shows available liquidity as of December 31, 2023 (in millions): [[GREPCENT_TABLE]] [["","December 31, 2023"],["","Capacity","","Outstanding","","Available"],["Revolving credit facility (1)","$","750","","","$","\u2014","","","$","750"],["Letters of credit (2)","320","","","106","","","214"],["Total credit","$","1,070","","","$","106","","","964"],["Cash and cash equivalents","","","","","5"],["Total liquidity","","","","","$","969"]] [[/GREPCENT_TABLE]] (1)Scheduled to expire September 2028. PGE has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay outstanding commercial paper. As of December 31, 2023, PGE had $146 million of commercial paper outstanding, therefore, the elected available credit capacity is $604 million. (2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year. As of December 31, 2023, PGE had a $750 million unsecured revolving credit facility scheduled to expire in September 2028. The facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% of the facility approve the extension request. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. Pursuant to the terms of the agreement, the revolving credit facility may be used as backup for commercial paper borrowings, to permit the issuance of standby letters of credit, and to provide cash for general corporate purposes. PGE may borrow for one, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2023, PGE had $146 million of commercial paper outstanding. PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets. Under the revolving credit facility, as of December 31, 2023, PGE had no borrowings, and no letters of credit issued. As a result, as of December 31, 2023, the aggregate unused available credit capacity under the revolving credit facility was $750 million, however, as PGE has elected to limit it’s borrowings to cover any potential need to repay outstanding commercial paper, the elected available credit capacity is $604 million. In addition, PGE has four letter of credit facilities under which the Company has total capacity of $320 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, which are considered off-balance sheet arrangements, letters of credit for a total of $106 million were outstanding as of December 31, 2023. PGE works to optimize its use of its letter of credit facility to manage energy trading margin. Long-term Debt—During 2023, PGE issued and funded a total of $600 million of FMBs. 66 Table of Contents In August 2023, PGE entered into a Bond Purchase Agreement related to the sale of $500 million in FMBs. The Bonds consist of: •a series, due in 2030, in the amount of $50 million that bear interest at an annual rate of 5.44%; •a series, due in 2033, in the amount of $150 million that bear interest at an annual rate of 5.48%; •a series, due in 2038, in the amount of $100 million that bear interest at an annual rate of 5.68%; •a series due in 2053, in the amount of $100 million that bear interest at an annual rate of 5.78%; and •a series due in 2059, in the amount of $100 million that bear interest at an annual rate of 5.83%. As of December 31, 2023, all series, totaling $500 million, were issued and funded in full. On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in First Mortgage Bonds (FMBs), $100 million of which was issued under PGE’s Green Financing Framework. The first half of FMBs funded in 2022 and the remaining $100 million funded in full on January 13, 2023. On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bore interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 87.5 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On March 1, 2023, this term loan was repaid in full. As of December 31, 2023, total long-term debt outstanding, net of $14 million of unamortized debt expense, was $3,985 million, of which $80 million is scheduled to mature in 2024. Equity—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at the market offering programs. As of December 31, 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties and under such agreements, the Company could have physically settled by delivering 1,714,971 shares to the counterparty in exchange for cash of $78 million. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity. In 2022, PGE entered into an EFSA in connection with the public offering of 10,100,000 shares of its common stock. Effective October 28, 2022, pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock with an initial value of $499 million, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters. PGE receives proceeds from the sale of the common stock when the EFSA is physically settled. In March 2023, the Company issued 7,178,016 shares pursuant to the EFSA and received net proceeds of $300 million. In June 2023, the Company issued 2,212,610 shares pursuant to the EFSA and received net proceeds of $92 million. On July 12, 2023, the Company issued 2,224,374 shares pursuant to the EFSA, settling the equity forward transaction, and received net proceeds of $92 million. For additional information on the EFSA, see Note 13, Equity-based Plans, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Capital Structure—PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade debt ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 44.6% and 43.3% as of December 31, 2023 and 2022, respectively. 67 Table of Contents Critical Accounting Policies and Estimates The preparation of consolidated financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain. Regulatory Accounting As a rate-regulated enterprise, PGE applies regulatory accounting, which includes the recognition of regulatory assets and liabilities on the Company’s consolidated balance sheets. Regulatory assets represent probable future revenue associated with certain incurred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited or refunded to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established or subject to approval by independent third-party regulators, prices are designed to recover the specific enterprise’s cost-of-service, and, in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Amortization of regulatory assets and liabilities is reflected in the statement of income over the period in which they are included in customer prices. If future recovery of regulatory assets is not probable, PGE would expense such items in the period such determination is made. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting. Discontinued application of regulatory accounting would have a material impact on the Company’s results of operations and financial position. For additional information on PGE’s regulatory assets and liabilities, see “Regulatory Matters” in the Overview section in this Item 7., and Note 7, Regulatory Assets and Liabilities in Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Asset Retirement Obligations PGE recognizes AROs for legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Estimates for ARO liabilities are generally based on site-specific studies and are periodically subject to updates and changes that may arise over time. Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions to ARO liabilities in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Accretion of the ARO liability is classified as Depreciation and amortization expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets. 68 Table of Contents As a co-owner of Colstrip, PGE has provided surety bonds, which are considered off-balance sheet arrangements, of $21 million as of December 31, 2023 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC. For additional information on AROs, see Note 8, Asset Retirement Obligations, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.” Contingencies PGE has various unresolved legal and regulatory matters about which there is inherent uncertainty, with the ultimate outcome contingent upon several factors. Such contingencies are evaluated using the best information available. A loss contingency is accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency and the reasons to the effect that it cannot be reasonably estimated are disclosed. A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate or range of potential loss is material. Established accruals reflect management’s assessment of inherent risks, credit worthiness, and complexities involved in the process. There can be no assurance as to the ultimate outcome of any particular contingency. For additional information on contingencies, see Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.—“Financial Statements and Supplementary Data.”