# Portland General Electric Co: Form 10-Q for the period ended Jun 30, 2024 - Company: [Portland General Electric Co](/companies/por.md) (CIK 784977) - Form: 10-Q - Filed: 2024-07-26 - Accepted by EDGAR: Jul 25, 2024, 17:40 ET - Period: 2024-06-30 - Accession: 0000784977-24-000133 - Inline XBRL: yes - Main document: https://www.sec.gov/Archives/edgar/data/784977/000078497724000133/por-20240630.htm - All documents and exhibits: https://www.sec.gov/Archives/edgar/data/784977/000078497724000133/ ## Figures reported in this filing Standardized XBRL line items for the period ended 2024-06-30. | Line item | Period | Value | XBRL concept | | --- | --- | ---: | --- | | Revenue | 3 months, 2024-04-01 to 2024-06-30 | $758.0m | us-gaap:Revenues | | Revenue | 6 months, 2024-01-01 to 2024-06-30 | $1.69bn | us-gaap:Revenues | | Operating income | 3 months, 2024-04-01 to 2024-06-30 | $116.0m | us-gaap:OperatingIncomeLoss | | Operating income | 6 months, 2024-01-01 to 2024-06-30 | $278.0m | us-gaap:OperatingIncomeLoss | | Interest expense | 3 months, 2024-04-01 to 2024-06-30 | $52.0m | us-gaap:InterestExpense | | Interest expense | 6 months, 2024-01-01 to 2024-06-30 | $103.0m | us-gaap:InterestExpense | | Income tax | 3 months, 2024-04-01 to 2024-06-30 | $7.0m | us-gaap:IncomeTaxExpenseBenefit | | Income tax | 6 months, 2024-01-01 to 2024-06-30 | $20.0m | us-gaap:IncomeTaxExpenseBenefit | | Net income | 3 months, 2024-04-01 to 2024-06-30 | $72.0m | us-gaap:ProfitLoss | | Net income | 6 months, 2024-01-01 to 2024-06-30 | $181.0m | us-gaap:ProfitLoss | | Diluted EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.69 | us-gaap:EarningsPerShareDiluted | | Basic EPS | 3 months, 2024-04-01 to 2024-06-30 | $0.69 | us-gaap:EarningsPerShareBasic | | Basic EPS | 6 months, 2024-01-01 to 2024-06-30 | $1.77 | us-gaap:EarningsPerShareBasic | | Diluted shares (weighted) | 3 months, 2024-04-01 to 2024-06-30 | 103,232,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding | | Diluted shares (weighted) | 6 months, 2024-01-01 to 2024-06-30 | 102,338,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding | | Operating cash flow | 6 months, 2024-01-01 to 2024-06-30 | $364.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities | | Capital expenditure | 6 months, 2024-01-01 to 2024-06-30 | $623.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment | | Dividends paid | 6 months, 2024-01-01 to 2024-06-30 | $96.0m | us-gaap:PaymentsOfDividends | | Current assets | at 2024-06-30 | $848.0m | us-gaap:AssetsCurrent | | Total assets | at 2024-06-30 | $11.58bn | us-gaap:Assets | | Current liabilities | at 2024-06-30 | $850.0m | us-gaap:LiabilitiesCurrent | | Total liabilities | at 2024-06-30 | $8.10bn | us-gaap:Liabilities | | Long-term debt | at 2024-06-30 | $4.35bn | us-gaap:LongTermDebtNoncurrent | | Current portion of debt | at 2024-06-30 | $80.0m | us-gaap:LongTermDebtCurrent | | Short-term borrowings | at 2024-06-30 | $0 | us-gaap:ShortTermBorrowings | | Shareholders' equity | at 2024-06-30 | $3.48bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest | ## Management's discussion and analysis As filed, 99,369 characters. ### 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. Portland General Electric Company’s (PGE, or the Company) expectations, beliefs, and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE’s expectations, beliefs, or projections will be achieved or accomplished. In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include: - governmental policies, legislative action, and regulatory audits, investigations, and actions, including those of the Federal Energy Regulatory Commission (FERC), the Public Utility Commission of Oregon (OPUC), the United States Securities and Exchange Commission (SEC), and the Division of Enforcement of the Commodity Futures Trading Commission, 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 Electricity Service Suppliers (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 2, along with “Regulatory Assets and Liabilities” in Note 3, Balance Sheet Components and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements in Item 1. Financial Statements of this Quarterly Report on Form 10-Q; - natural or human-caused disasters and other risks, including, but not limited to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire, accidents, equipment failure, acts of terrorism, computer system outages, and other events that disrupt PGE operations, damage PGE facilities and systems, cause the release of harmful materials, cause fires, and subject the Company to liability; - 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; - 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; - 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 such costs; - PGE’s ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk 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, results of operations, 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 and outlook on such 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 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; - 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; - 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 generation and transmission projects, including, but not limited to regulatory processes, legal actions, 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 condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC. PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity. 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 in the State of Oregon (State). ### 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 228 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% clean and renewable electricity by 2035 and 100% 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. As of June 30, 2024, the Green Future Impact Program has an approved capacity of 750 MW nameplate. Through this voluntary program, the Company seeks to support customers’ clean energy acceleration. ***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 event, see “Declared States of Emergency” within this Overview section of this Item 2. In August 2023 the region experienced a record-breaking heat wave with temperatures reaching all-time recorded highs for the month. This resulted in a peak load demand of 4,498 MW, exceeding the Company’s previous all-time peak load demand, and surpassing the prior summer peak load by nearly 6%. The increase and severity of 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 Integrated Resource Plan (IRP). PGE filed its first combined IRP and CEP with the OPUC in March 2023. That filing projected PGE’s resource and capacity needs over the next 20 years and proposed an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements. PGE 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 2023 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 combined CEP/IRP Update to be filed in the first quarter of 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP. #### 2021 All-Source RFP Pursuant to the 2021 All-Source RFP process, seeking approximately 1,000 MW of renewable resources and non-emitting dispatchable capacity, PGE entered into agreements to acquire resources as follows: - *Clearwater Wind Development (Clearwater)—*PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. entered into agreements to construct a 311 MW wind energy facility in Eastern Montana. PGE owns 208 MW of production capacity of the facility. Subsidiaries of NextEra Energy Resources, LLC, which operates the facility, owns the remaining 103 MW of production capacity and sells their portion of the output to PGE under a 30-year PPA. The company owned portion of the project was placed in-service during the first quarter of 2024 with a total cost of $424 million, including AFUDC. - *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. As of June 30, 2024, the Company has recorded $129 million, including AFUDC, in CWIP for the Seaside Grid. - *Constable BESS (formerly Evergreen)—*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. As of June 30, 2024, the Company has recorded $103 million, including AFUDC, in CWIP for the Constable BESS. - *Sundial BESS (formerly 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. Emissions associated with energy used to charge the BESS are accounted for when they are emitted from the generating facility. BESS projects do not add incremental emissions to the grid, and therefore, are non-emitting dispatchable capacity resources. The BESS projects will qualify for the federal investment tax credit (ITC). The Clearwater agreements qualify for production tax credits (PTCs) and are eligible under Oregon’s Renewable Portfolio Standard (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 in June 2023. In August 2023, PGE filed a notice asking the Court to dismiss the case. That motion remains pending. Oral argument in this case occurred March 18, 2024. The parties await a decision from the Court. 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, in March 2023, filed a motion to dismiss. In September 2023, the judge granted PGE’s motion to dismiss. In November 2023, NewSun filed a notice of appeal in the Court of Appeals of the State of Oregon. Opening briefs in the Appeal were filed March 1, 2024, with PGE and OPUC responses filed July 12, 2024. Oral arguments are expected to occur in late 2024 or early 2025. PGE cannot predict the outcome of these proceedings or potential impact, if any, to its 2021 All-Source RFP process. #### 2023 All-Source RFP PGE filed notice with the OPUC in January 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. PGE filed the draft 2023 All-Source RFP with the OPUC in May 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. Bids were submitted in the first quarter of 2024 and are currently being evaluated based on the OPUC-approved scoring methodology. PGE plans to file for acknowledgement of a proposed final shortlist in the third quarter of 2024 with a final selection currently planned for late 2024 or early 2025. #### 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. On May 28, 2024, PGE signed a non-binding memorandum of understanding in the development of the North Plains Connector, an approximately 415-mile, high-voltage direct-current (HVDC) transmission line to be constructed with endpoints near Bismarck, North Dakota and Colstrip, Montana. The parties will now work to finalize definitive agreements regarding the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. The North Plains Connector would be the nation’s first HVDC transmission connection among three regional U.S. electric energy markets, providing additional flexibility and the sharing of resources across multiple time zones. The transmission line would provide PGE with 600 MW of transfer capacity, access to diverse energy resources, enhanced wholesale markets, and ease congestion on the existing western transmission system. ***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 has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC, as required by state law, to coordinate 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 in the current year 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 the Company’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. In the six months ended June 30, 2024, PGE invested $15 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2024 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 DERs and flexible loads 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, the various 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. While the OPUC Staff is in the process of reviewing whether to modify the current DSP guidelines, PGE plans to file its next DSP in the fourth quarter of 2024. 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. ***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 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. This second TE plan considers current and planned activities, along with forecasted EV loads 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 with its planned activities was accepted by the OPUC on October 17, 2023. 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, federal, and private 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, utility workforce development, and regional transmission capacity constraints. As of June 30, 2024, PGE has been associated with the submission of 38 grant applications as the Prime or Sub-recipient/Supporter and has been awarded 11 grants totaling $307.8 million, including the following: - *U.S. Department of Energy (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 CTWS to support adaptation and response strategies. The U.S DOE, CTWS, 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 line upgrade as part of a multi-year process. 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 transferred 2023 credits with the final transfer occurring in the first quarter of 2024. On April 16, 2024, PGE received approval from the OPUC to transfer 2024 and 2025 PTCs and record any difference in the full value and the discounted value in a property balancing account. PGE has entered into an agreement to transfer 2024 and 2025 PTCs and expects to generate and transfer approximately $58 million in PTCs in 2024. 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 2021—***In 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 baseline emissions levels, which for PGE, is calculated by using average annual emissions for the years 2010 through 2012. HB 2021 requires utilities to develop a CEP for meeting the targets, concurrent with each IRP, that results in an affordable, reliable, and clean electric system. In reviewing a CEP, the OPUC must ensure that utilities create a plan that is in the public interest, demonstrate continual progress toward meeting the targets, and take actions as soon as practicable that facilitate rapid reduction of GHG emissions. A law adopted in 2009 requires retail electricity providers to annually report to the Oregon Department of Environmental Quality (ODEQ) the GHG emissions associated with electricity used to serve retail customers. In the target years of 2030, 2035, and 2040, and every year thereafter in the target period, the OPUC will use the data reported to the ODEQ for that compliance year to determine whether the reduction targets are met under HB 2021. ***RPS standards and related laws—***In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable sources by dates certain 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, has accelerated depreciation of Colstrip 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 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements” for information regarding legal proceedings related to Colstrip. Any reduction in generation from Colstrip has the potential to provide 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: - established RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040; - limited 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 - provided opportunity to pursue recovery of energy storage costs related to renewable energy in the Company’s Renewable Adjustment Clause (RAC) filings. PGE believes it is on track to meet the 2025 RPS threshold. ***EPA Regulations for Electric Generating Facilities—***On April 25, 2024, the United States Environmental Protection Agency (EPA) released a package of final regulations pertaining to electric generation facilities. The regulations include: - Greenhouse gas regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act (CAA). The rule finalizes (a) the repeal of the Affordable Clean Energy rule; (b) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric generating units; and (c) revisions to existing performance standards for new, reconstructed, or heavily modified fossil fuel-fired stationary combustion turbine electric generating units. - Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (the ELG Rule), which applies to wastewater discharges from coal-based generating units and establishes pollution control requirements, building upon the 2015 and 2020 ELG Rules. The rule includes a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034. - Updated Mercury and Air Toxics Standards, pursuant to section 112 of the CAA, which sets emissions limits for filterable particulate matter for coal-based generating units. The rule reduces those limits from the standards that were originally set in 2012. PGE continues to evaluate each of these rules to assess the impact it may have on the Company’s continuing investment in Colstrip, which could be material. PGE notes that a substantial number of legal challenges have been filed regarding these rules. These challenges, if successful, could affect the applicability to PGE and Colstrip specifically. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process. In addition, the regulations included Disposal of Coal Combustion Residuals from Electric Utilities – Legacy CCR Surface Impoundments. This rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants, and CCR management units at active and inactive power plants. PGE has assessed the potential impact of the CCR regulation changes and believes it will not have a material impact on the Company’s current Asset Retirement Obligations. ### 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—***On February 29, 2024, PGE filed with the OPUC a GRC based on a 2025 test year (2025 GRC) that seeks a $225 million increase in the annual revenue requirement related primarily to recovery of costs associated with non-emitting battery projects, an increase in base business costs for upgrades to PGE's transmission and distribution system, and investments in strengthening and safeguarding the grid to meet growing customer demand and bolster reliability. PGE continues to build a stronger grid designed to withstand severe weather and allow energy to flow from more resources to improve reliability, resiliency, and capability to deliver safe, dependable, clean electricity to customers. The total increase in annual revenue requirement includes an increase of $37 million as a result of higher net variable power costs expected in 2025, reflected in the Annual Power Cost Update Tariff (AUT) also filed, separately, with the OPUC February 29, 2024 (OPUC Docket UE 436). The NVPC projection will be updated periodically during 2024. Other key items in the 2025 GRC filing include requests for a Renewable Automatic Adjustment Clause mechanism for standalone energy storage and an investment recovery mechanism. The proposed net increase in annual revenue requirement in the 2025 GRC was based upon a: - capital structure of 50% debt and 50% equity; - return on equity of 9.75%; - cost of capital of 7.189%; and - rate base of $7.5 billion. Regulatory review of the 2025 GRC is expected to continue throughout 2024. The Company cannot predict the ultimate outcome of the remaining regulatory process. A final order on the 2025 GRC is targeted to be issued by the OPUC by the end of 2024, with new customer prices to take effect January 1, 2025. The 2025 GRC filing (OPUC Docket UE 435) and the 2025 AUT filing, including copies of direct testimony and exhibits, are available on the OPUC website at www.oregon.gov/puc. ***Declared states of emergency—***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. As a result of the historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to seek recovery of incremental storm expenses through the previously filed emergency deferral, as the OPUC had pre-authorized for costs associated with declared states of emergency. 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, as of June 30, 2024, has deferred as regulatory assets $44 million, including interest, of the costs to repair damage to PGE’s transmission and distribution systems and restore power to customers. The OPUC maintains responsibility to review utility requests to amortize deferred amounts into customer prices, including a review of utility prudence in a future proceeding, among other requirements, which would include an earnings test. For further information, see “*January 2024 storm and damage”* in the Regulatory Assets and Liabilities section of Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.” On July 5, 2024, the Governor of Oregon declared a statewide emergency for a heat wave that engulfed the region. The Company is in the process of determining costs that resulted from the heat wave that may be eligible for recovery under the Declared state of emergency deferral. ***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 2024 AUT included a final increase in power costs for 2024, and a corresponding increase in annual revenue requirement, of $216 million from 2023 levels, which were reflected in customer prices effective January 1, 2024. ***Portland Harbor Environmental Remediation Account (PHERA) mechanism—***The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of June 30, 2024, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision (ROD) issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position. The impact of such costs to the Company’s results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the 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 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.” ***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 to resume decoupling, with certain modifications. As stipulated in the 2024 GRC settlement agreement, PGE made a tariff filing on January 26, 2024 that proposed weather-normalized decoupling. At a public meeting on June 11, 2024, the OPUC permanently suspended PGE’s proposed tariff, effectively denying the proposal. ***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, which went into service in January 2024. See “*Clearwater RAC”* in Note 3, Regulatory Assets and Liabilities, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for more information regarding the timing of the tariff, annual revenue requirement, and related deferral. ### Operating Activities In addition to electricity provided by PGE’s own generation portfolio, to meet retail load requirements and balance energy supply with customer demand, the Company purchases and sells electricity in the wholesale market. To fuel its generation portfolio, the Company purchases natural gas in the United States and Canada and sells excess gas back into the wholesale market. PGE also performs portfolio management and wholesale market services for third parties in the region. The Company participates in the California Independent System Operator's (CAISO) western Energy Imbalance Market (EIM), which allows, among other things, more renewable energy integration into the grid by better complementing the variable output of renewable resources. PGE recently signed the implementation agreement to join the CAISO’s Extended Day-Ahead Market (EDAM) to build on the success of the western EIM and help provide the Company and its customers access to more affordable, reliable and clean energy. Utilities that participate in the EDAM, expected to begin operating in 2026, will bid their anticipated energy demand and generating resources into the market a day ahead of expected usage. The EDAM will then optimize generation resources and the energy needed for all market participants, allowing them to receive the least costly and cleanest energy to meet their energy needs. The EDAM takes advantage of existing technology and systems PGE has deployed and leverages the Company’s transmission system to connect regional resources across a common market, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert Southwest. In its ongoing effort to benefit retail and wholesale customers, in 2023, PGE joined the Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP), which could become a binding commitment in 2026 or 2027. The WRAP represents a regional framework to more effectively address resource adequacy, enhance reliability, integrate clean energy, and manage costs through resource diversification and capacity sharing across a wide geographic footprint and broad pool of participants across the West. PGE generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues, cash flows, and income from operations to fluctuate from period to period. Summer peak deliveries have continued to exceed those of the winter months for nearly ten years, generally resulting from growing air conditioning demand and the trend toward a warmer overall climate. In August 2023, demand reached a new all-time high, surpassing the previous mark, which was set in summer 2021. Historically, PGE had experienced its highest MWa deliveries and retail energy sales during the winter heating season. Although a new record high winter peak load was set as recent as December 2022, the summer peak deliveries in each year since 2021 have exceeded that winter peak. 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 customer type for the periods indicated: | Energy deliveries (MWhs in thousands): Retail: | Three Months Ended June 30, 2024 | 2023 | % Change | % Change (Weather- Adjusted) | Six Months Ended June 30, 2024 | 2023 | % Change | % Change (Weather- Adjusted) | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Residential | 1,608 | 1,730 | (7)% | (1)% | 3,851 | 4,057 | (5)% | —% | | Commercial | 1,548 | 1,595 | (3) | — | 3,176 | 3,252 | (2) | (1) | | Industrial | 1,204 | 1,140 | 6 | 7 | 2,390 | 2,211 | 8 | 9 | | Subtotal | 4,360 | 4,465 | (2) | 1 | 9,417 | 9,520 | (1) | 2 | | Direct access: | | | | | | | | | | Commercial | 127 | 154 | (18) | (18) | 247 | 283 | (13) | (13) | | Industrial | 451 | 430 | 5 | 5 | 847 | 866 | (2) | (2) | | Subtotal | 578 | 584 | (1) | (1) | 1,094 | 1,149 | (5) | (5) | | Total retail | 4,938 | 5,049 | (2) | 1% | 10,511 | 10,669 | (1) | 1% | | Wholesale | 2,104 | 1,453 | 45 | | 4,283 | 2,849 | 50 | | | Total | 7,042 | 6,502 | 8% | | 14,794 | 13,518 | 9% | | | Average number of retail customers: | Three Months Ended June 30, 2024 | | 2023 | | Six Months Ended June 30, 2024 | | 2023 | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Residential | 828,355 | 88% | 814,419 | 88% | 826,297 | 88% | 814,187 | 88% | | Commercial | 113,577 | 12 | 112,190 | 12 | 113,223 | 12 | 112,333 | 12 | | Industrial | 208 | — | 196 | — | 206 | — | 195 | — | | Direct access | 496 | — | 539 | — | 505 | — | 541 | — | | Total | 942,636 | 100% | 927,344 | 100% | 940,231 | 100% | 927,256 | 100% | Total retail energy deliveries for the six months ended June 30, 2024 decreased 1% compared with the six months ended June 30, 2023, as decreases in residential and commercial deliveries more than offset the increase from industrial customers. Residential weather-adjusted deliveries saw average usage per customer 1.6% lower during the first six months of 2024 compared with 2023, while the average number of residential customers was 1.5% greater during 2024 than 2023. For the six months ended June 30, 2024, milder temperatures have resulted in lower Total Retail Energy deliveries when compared to the same six months of 2023. During the three-month period ended March 31, 2024 compared to the same three months of 2023, the impact of weather on Total Retail deliveries was negative with overall warmer than average, and considerably warmer than the prior year, temperatures experienced. In the three-month period ended June 30, 2024, total heating degree-days were comparable to the same period of 2023, as warmer temperatures in April 2024 were largely offset by cooler temperatures the following month, while both years were, in total for the quarter, warmer than average. May 2023 produced an unusually high number of cooling degree-days and elevated deliveries occurred, which resulted in weather having an overall negative impact on deliveries in the second quarter of 2024 compared to the same period of 2023. The industrial class continues to show growth in energy deliveries, up 5.4% and 5.2% in the three months and six months ended June 30, 2024, respectively, compared to the same periods in 2023, reflecting strength in the digital services sector. The following table indicates the number of heating and cooling degree-days for the three and six months ended June 30, 2024 and 2023, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport: | | Heating Degree-days 2024 | 2023 | Avg. | Cooling Degree-days 2024 | 2023 | Avg. | | --- | ---: | ---: | ---: | ---: | ---: | ---: | | First Quarter | 1,755 | 1,927 | 1,838 | — | — | — | | April | 310 | 404 | 364 | — | 12 | 3 | | May | 192 | 105 | 178 | 23 | 87 | 26 | | June | 45 | 45 | 66 | 85 | 96 | 79 | | Second Quarter | 547 | 554 | 608 | 108 | 195 | 108 | | Year-to-date | 2,302 | 2,481 | 2,446 | 108 | 195 | 108 | | (Decrease) increase from the 15-year average | (6)% | 1% | | —% | 81% | | The Company’s cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. Had the cap limit been fully subscribed and utilized, 13% of PGE’s total retail energy deliveries for the first six months of 2024 would have been to these customers. In 2020, PGE began offering service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 17% of the Company’s energy deliveries could have been supplied by ESSs to Direct Access customers. Actual deliveries to Direct Access customers of energy supplied by ESSs represented 10% of PGE’s total retail energy deliveries for the first six months of 2024 and 2023. **Power Operations—**PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. The Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. PGE continuously makes economic dispatch decisions based on numerous factors, such as plant availability, customer demand, river flows, wind conditions, and current wholesale prices. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period and impacts NVPC and income from operations. The following table provides information regarding the performance of the Company’s generating resources for the six months ended June 30, 2024 and 2023: | Generation: Thermal: | Plant availability (1) 2024 | 2023 | Actual energy provided compared to projected levels (2) 2024 | 2023 | Actual energy provided as a percentage of total system load 2024 | 2023 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | | Natural gas | 77% | 80% | 91% | 93% | 32% | 35% | | Coal (3) | 65 | 89 | 86 | 93 | 5 | 8 | | Wind (4) | 91 | 98 | 102 | 97 | 11 | 8 | | Hydro | 94 | 91 | 93 | 80 | 5 | 5 | (1) Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2) Projected levels of energy are included as part of PGE’s AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources. (3) Plant availability reflects Colstrip, which PGE does not operate. (4) Plant availability includes Wheatridge Renewable Energy Facility and Clearwater, which PGE does not operate. Energy received from PGE-owned and jointly-owned thermal plants during the six months ended June 30, 2024 compared to 2023 decreased 2%. This decrease was primarily driven by economic dispatch decisions. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE’s thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year. Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 31% during the six months ended June 30, 2024 compared to 2023 primarily due to the addition of capacity under two purchased hydro contracts in 2024. Energy purchased from mid-Columbia and other regional hydroelectric projects increased 37% while energy generated by the Company-owned facilities increased 10% during the six months ended June 30, 2024. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See “*Purchased power and fuel”* in the Results of Operations section in this Item 2, for further detail on regional hydro results. Energy received from PGE-owned and under contract wind resources increased 45% during the six months ended June 30, 2024 compared to 2023 primarily due to the addition of Clearwater in 2024. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. Under PGE’s PCAM, the Company may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed “deadband” limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. The following is a summary of the results of the Company’s PCAM as calculated for regulatory purposes for the six months ended June 30, 2024 and 2023, respectively: - For the six months ended June 30, 2024, actual NVPC was $52 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2024 is currently estimated to be below the baseline and within the established deadband range. Accordingly, there is no estimated refund to customers expected under the PCAM for 2024. - For the six months ended June 30, 2023, actual NVPC was $19 million above baseline NVPC. For the year ended December 31, 2023, actual NVPC was $5 million above baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection from customers was recorded for 2023. A portion of the costs related to a January 2024 storm, which qualified as a Reliability Contingency Event (RCE) as approved by the OPUC in PGE’s 2024 GRC, was deferred as a regulatory asset. 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. For more on the 2024 RCE, see “*Regulatory Assets and Liabilities”* in Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.” ### Results of Operations The following tables provide financial and operational information to be considered in conjunction with management’s discussion and analysis of results of operations. The results of operations are as follows for the periods presented (dollars in millions): | | Three Months Ended June 30, 2024 | 2023 | % Increase (Decrease) 2024 | Six Months Ended June 30, 2023 | | % Increase (Decrease) | | --- | ---: | ---: | ---: | ---: | ---: | ---: | | **Total revenues** | $758 | $648 | 17% | $1,687 | $1,396 | 21% | | **Operating expenses:** | | | | | | | | Purchased power and fuel | 275 | 220 | 25 | 680 | 524 | 30 | | Generation, transmission and distribution | 107 | 101 | 6 | 206 | 194 | 6 | | Administrative and other | 97 | 93 | 4 | 192 | 173 | 11 | | Depreciation and amortization | 122 | 113 | 8 | 243 | 224 | 8 | | Taxes other than income taxes | 41 | 40 | 3 | 88 | 83 | 6 | | Total operating expenses | 642 | 567 | 13 | 1,409 | 1,198 | 18 | | Income from operations | 116 | 81 | 43 | 278 | 198 | 40 | | **Interest expense, net\*** | 52 | 41 | 27 | 103 | 85 | 21 | | **Other income:** | | | | | | | | Allowance for equity funds used during construction | 6 | 4 | 50 | 11 | 7 | 57 | | Miscellaneous income, net | 9 | 5 | 80 | 15 | 17 | (12) | | Other income, net | 15 | 9 | 67 | 26 | 24 | 8 | | Income before income tax expense | 79 | 49 | 61 | 201 | 137 | 47 | | **Income tax expense** | 7 | 10 | (30) | 20 | 24 | (17) | | **Net income** | **72** | **39** | **85** | **181** | **113** | **60** | | Other comprehensive income | — | 1 | — | 1 | 1 | — | | **Net income and Comprehensive income** | **$72** | **$40** | **80%** | **$182** | **$114** | **60%** | \* Includes an allowance for borrowed funds used during construction of $4 million and $3 million for the three months ended June 30, 2024 and 2023, respectively, and $8 million and $5 million for the six months ended June 30, 2023, respectively. **Net income** for the three months ended June 30, 2024 increased $33 million, or 85%, compared to the three months ended June 30, 2023, driven largely by an increase in Income from Operations. Retail revenues were up not only as a result of general price increases but also as a result of an increase in prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT. Purchased power and fuel expense rose 25% over the same period of 2023, although much of that increase was volume driven, as wholesale energy prices have shown a decline from the same period a year ago. While retail energy deliveries remained relatively comparable period over period, total system load increased 8%, driven by increases in wholesale energy deliveries. Generation, transmission and distribution expenses were up due to maintenance activities, vegetation management, and service restoration work. Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, were both higher, as anticipated, and largely offset by increased revenues. Other income, net benefited in 2024 from higher AFUDC credits, while a reduced Income tax expense reflects increases in PTC benefits. Net income for the six months ended June 30, 2024 increased $68 million, or 60%, compared to the same period of 2023. Retail revenues increased due to higher prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT, as well as general price increases, with a partial offset as a result of a slight reduction in Total Retail deliveries. Wholesale revenues increased, driven by a 50% increase in deliveries. The increase in Administrative and general expense reflects increases in various categories including customer related items, which was largely due to the amortization of previously deferred COVID-19 expenses now being collected in customer prices and offset in revenues, wages and benefits, outside services, and regulatory expense. Increases in Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, were anticipated and largely offset by increased revenues. Other income, net increased in 2024 partially due to the higher AFUDC credits, while a reduced Income tax expense reflects increases in PTC benefits. **Total revenues** consist of the following for the periods presented (dollars in millions): | Retail: | Three Months Ended June 30, 2024 | | 2023 | | Six Months Ended June 30, 2024 | | 2023 | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Residential | $307 | 40% | $279 | 44% | $722 | 43% | $641 | 46% | | Commercial | 219 | 29 | 196 | 30 | 446 | 27 | 393 | 28 | | Industrial | 104 | 14 | 87 | 13 | 206 | 12 | 169 | 12 | | Subtotal | 630 | 83 | 562 | 87 | 1,374 | 82 | 1,203 | 86 | | Direct access: | | | | | | | | | | Commercial | 3 | — | 2 | — | 5 | — | 4 | — | | Industrial | 6 | 1 | 5 | 1 | 10 | 1 | 9 | 1 | | Subtotal | 9 | 1 | 7 | 1 | 15 | 1 | 13 | 1 | | Subtotal Retail | 639 | 84 | 569 | 88 | 1,389 | 83 | 1,216 | 87 | | Alternative revenue programs, net of amortization | (3) | — | 2 | — | (14) | (1) | 5 | — | | Other accrued revenues, net | 4 | — | (4) | (1) | 5 | — | (3) | — | | Total retail revenues | 640 | 84 | 567 | 87 | 1,380 | 82 | 1,218 | 87 | | Wholesale revenues | 99 | 13 | 62 | 10 | 275 | 16 | 150 | 11 | | Other operating revenues | 19 | 3 | 19 | 3 | 32 | 2 | 28 | 2 | | Total revenues | $758 | 100% | $648 | 100% | $1,687 | 100% | $1,396 | 100% | *Total retail revenues—*The following items contributed to the increase in Total retail revenues for the three and six months ended June 30, 2024 compared to the same periods in 2023 (in millions): | | Three Months Ended | Six Months Ended | | --- | ---: | ---: | | June 30, 2023 | $567 | $1,218 | | Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel) | 48 | 102 | | Average price of energy deliveries due primarily to customer price increases | 33 | 81 | | Recovery of deferrals for 2020 Wildfire, 2021 ice storm, and COVID-19 | (1) | 4 | | Retail energy deliveries driven by changes in customer load | (7) | (11) | | Clearwater RAC deferral | (3) | (13) | | Combination of various supplemental tariffs and adjustments | 3 | (1) | | June 30, 2024 | $640 | $1,380 | | Change in Total retail revenues | $73 | $162 | 51 *Wholesale revenues* result from sales of electricity to utilities and power marketers made in the Company’s efforts to meet the needs of, and obtain reasonably priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. For the three months ended June 30, 2024, Wholesale revenues increased $37 million, or 60%, from the three months ended June 30, 2023 driven primarily by a $28 million increase that resulted from higher sales volumes. Wholesale revenues for the six months ended June 30, 2024 increased $125 million, or 83%, from the six months ended June 30, 2023, as a 50% increase in sales volumes added $76 million to revenues and the average wholesale sales price was up 22%, due largely to the market conditions surrounding the January 2024 storm event in the region. *Other operating revenues* for the three months ended June 30, 2024 were comparable with the same period in 2023. In the six months ended June 30, 2024, Other operating revenues were up $4 million compared to the same period of 2023, as transmission related revenues drove the increase. **Purchased power and fuel** expense includes the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts. The following items contributed to the change in Purchased power and fuel for the three and six months ended June 30, 2024 compared to the same period in 2023 (dollars in millions, except for average variable power cost per Megawatt hour (MWh): | | Three Months Ended | Six Months Ended | | --- | ---: | ---: | | June 30, 2023 | $220 | $524 | | Average variable power cost per MWh | 28 | 155 | | Total system load | 27 | 75 | | 2021 PCAM deferral amortization | — | 1 | | 2024 RCE deferral | — | (75) | | June 30, 2024 | 275 | 680 | | Change in Purchased power and fuel | $55 | $156 | | Average variable power cost per MWh: | | | | June 30, 2023 | $35.19 | $40.01 | | June 30, 2024 | $40.10 | $52.00 | | Total system load (MWhs in thousands): | | | | June 30, 2023 | 6,138 | 12,922 | | June 30, 2024 | 6,774 | 14,384 | For the three months ended June 30, 2024, the $28 million increase related to the change in average variable power cost per MWh was driven by a 6% increase in the average cost of purchased power and a 26% increase in the average cost for the Company’s own generation, driven primarily by price risk management activity. The $27 million increase resulting from the overall mix of purchased power and generation used to meet total system load was primarily due to a 15% increase of energy obtained from purchased power and a 5% increase in the Company’s own generation. For the six months ended June 30, 2024, the $155 million increase related to the change in average variable power cost per MWh was driven by a 26% increase in the average cost of purchased power and a 27% increase in the average cost for the Company’s own generation, driven primarily by higher physical power and natural gas prices due to severe weather events in the first quarter. The $75 million increase related to total system load was comprised of an 18% increase of energy obtained from purchased power primarily due to the addition of capacity under two purchased hydro contracts in 2024, and a 6% increase in the Company’s own generation primarily due to the addition of Clearwater in 2024. PGE’s sources of energy, total system load, and retail load requirement are as follows for the periods presented: | Sources of energy (MWhs in thousands): Generation: Thermal: | Three Months Ended June 30, 2024 | | 2023 | | Six Months Ended June 30, 2024 | | 2023 | | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Natural gas | 1,641 | 24% | 1,624 | 26% | 4,669 | 32% | 4,520 | 35% | | Coal | 255 | 4 | 432 | 7 | 781 | 5 | 1,028 | 8 | | Total thermal | 1,896 | 28 | 2,056 | 33 | 5,450 | 37 | 5,548 | 43 | | Hydro | 345 | 5 | 374 | 6 | 738 | 5 | 669 | 5 | | Wind | 948 | 14 | 602 | 10 | 1,538 | 11 | 1,083 | 8 | | Total generation | 3,189 | 47 | 3,032 | 49 | 7,726 | 53 | 7,300 | 56 | | Purchased power: | | | | | | | | | | Hydro | 1,851 | 27 | 1,412 | 23 | 3,415 | 24 | 2,492 | 19 | | Wind | 415 | 6 | 244 | 4 | 721 | 5 | 476 | 4 | | Solar | 350 | 5 | 394 | 6 | 497 | 3 | 539 | 4 | | Natural Gas | — | — | — | — | 94 | 1 | 11 | — | | Waste, Wood, and Landfill Gas | 46 | 1 | 38 | 1 | 85 | 1 | 81 | 1 | | Source not specified | 923 | 14 | 1,018 | 17 | 1,846 | 13 | 2,023 | 16 | | Total purchased power | 3,585 | 53 | 3,106 | 51 | 6,658 | 47 | 5,622 | 44 | | Total system load | 6,774 | 100% | 6,138 | 100% | 14,384 | 100% | 12,922 | 100% | | Less: wholesale sales | (2,104) | | (1,453) | | (4,283) | | (2,849) | | | Retail load requirement | 4,670 | | 4,685 | | 10,101 | | 10,073 | | 53 Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows: | Sources of energy (MWhs in thousands): PURPA purchased power: | Three Months Ended June 30, 2024 | 2023 | Six Months Ended June 30, 2024 | 2023 | | --- | ---: | ---: | ---: | ---: | | Hydro | 11 | 11 | 21 | 19 | | Wind | 10 | 8 | 15 | 14 | | Solar | 196 | 201 | 287 | 303 | | Waste, Wood, and Landfill Gas | 5 | 30 | 33 | 58 | | Total | 222 | 250 | 356 | 394 | The following table presents the forecast April-to-September 2024 and actual 2023 runoff at particular points of major rivers relevant to PGE’s hydro resources: | Location | Runoff as a Percent of Normal\* 2024 Forecast | 2023 Actual | | --- | ---: | ---: | | Columbia River at The Dalles, Oregon | 75% | 83% | | Mid-Columbia River at Grand Coulee, Washington | 73 | 79 | | Clackamas River at Estacada, Oregon | 93 | 101 | | Deschutes River at Moody, Oregon | 94 | 98 | \* 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** for the three and six months ended June 30, 2024 increased compared to the same periods in 2023 as follows (in millions): | | Three Months Ended | Six Months Ended | | --- | ---: | ---: | | June 30, 2023 | $158 | $374 | | Purchased power and fuel expense | 55 | 230 | | Wholesale revenues | (37) | (125) | | 2021 PCAM deferral amortization | $— | 1 | | 2024 RCE deferral | $— | (75) | | June 30, 2024 | $176 | $405 | | Change in NVPC | $18 | $31 | For further information regarding NVPC in relation to the PCAM, see “*Purchased power and fuel expense”* and “*Revenues”* within this “Results of Operations” for more details. For the three months ended June 30, 2024 and 2023, actual NVPC was $31 million below and $5 million above baseline NVPC, respectively. For the six months ended June 30, 2024 and 2023, actual NVPC was $52 million below and $19 million above baseline NVPC, respectively. Based on forecast data, NVPC for the year ending December 31, 2024 is currently estimated to be below the baseline and within the deadband. Accordingly, there is no estimated refund to customers expected under the PCAM for 2024. **Generation, transmission and distribution** increased as follows for the three and six months ended June 30, 2024 compared to the same periods in 2023 (in millions): | | Three Months Ended | Six Months Ended | | --- | ---: | ---: | | June 30, 2023 | $101 | $194 | | Generating facility expenses driven by increased major maintenance activities | 6 | 10 | | Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses | 5 | 9 | | Service restoration and storm response costs | 4 | 7 | | Miscellaneous expenses | (9) | (14) | | June 30, 2024 | $107 | $206 | | Change in Generation, transmission and distribution | $6 | $12 | **Administrative and other** increased as follows for the three and six months ended June 30, 2024 compared to the same periods in 2023 (in millions): | | Three Months Ended | Six Months Ended | | --- | ---: | ---: | | June 30, 2023 | $93 | $173 | | Amortization of COVID-19 bad debt expense deferral | — | 4 | | Regulatory and Professional services costs | — | 2 | | Employee compensation and benefits | 1 | 3 | | Customer related costs | 2 | 3 | | Miscellaneous expenses | 1 | 7 | | June 30, 2024 | $97 | $192 | | Change in Administrative and other | $4 | $19 | PGE commenced amortization of previously deferred COVID-19 related bad debt expenses on April 1, 2023. For the six months ended June 30, 2024, the Company amortized $7 million of COVID-19 related bad debt expense that was offset in revenues. **Depreciation and amortization** expense increased $9 million and $19 million in the three and six months ended June 30, 2024, respectively, compared to the same periods in 2023. The increase was primarily due to higher utility plant balances. **Taxes other than income taxes** increased $1 million and $5 million in the three and six months ended June 30, 2024, respectively, compared to the same periods in 2023. The increases were driven by higher property taxes and franchise fees. **Interest expense, net** increased $11 million and $18 million, respectively, in the three and six months ended June 30, 2024 compared to the same periods in 2023, primarily due to higher long-term debt balances. **Other income, net** increased $6 million and $2 million for the three and six months ended June 30, 2024, respectively, compared to the same periods in 2023. The increase was primarily driven by higher AFUDC from higher construction work in process balances. **Income tax expense** decreased $3 million and $4 million, respectively, in the three and six months ended June 30, 2024, compared to the same period in 2023, driven by higher production tax credit benefits offset by higher tax expense driven by higher pre-tax income. ### Critical Accounting Policies and Estimates There have been no material changes to the Company’s critical accounting policies and estimates as previously disclosed in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 20, 2024. ### LIQUIDITY AND CAPITAL RESOURCES #### Liquidity PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves. The following summarizes PGE’s cash flows for the periods presented (in millions): | | Six Months Ended June 30, 2024 | 2023 | | --- | ---: | ---: | | Cash and cash equivalents, beginning of period | $5 | $165 | | Net cash provided by (used in): | | | | Operating activities | 364 | 143 | | Investing activities | (639) | (574) | | Financing activities | 276 | 279 | | Increase (decrease) in cash and cash equivalents | 1 | (152) | | Cash and cash equivalents, end of period | $6 | $13 | 56 **Cash Flows from Operating Activities—**Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the six months ended June 30, 2024 compared with the six months ended June 30, 2023 (in millions): | | Increase/ (Decrease) | | --- | ---: | | Net income | $68 | | Accounts receivable and Unbilled revenue | (66) | | Margin deposits activity | 82 | | Accounts payable | 199 | | Regulatory deferral activity | (130) | | Depreciation and amortization | 19 | | Deferred income taxes | 21 | | Tax credit sales | 13 | | Other miscellaneous changes | 15 | | **Net change in cash flow from operations** | $221 | PGE estimates that non-cash charges for depreciation and amortization in 2024 will range from $475 million to $525 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $700 million to $800 million. **Cash Flows from Investing Activities—**Net cash used in investing activities for the six months ended June 30, 2024 increased $65 million when compared with the six months ended June 30, 2023. Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities, which increased $50 million. Excluding AFUDC, the Company plans to make capital expenditures of $1.3 billion in 2024, which it expects to fund with cash to be generated from operations during 2024, as discussed above, the issuance of short- and long-term debt securities, and issuances of shares pursuant to the at-the-market offering program. For additional information, see “*Debt and Equity Financings”* in this Liquidity and Capital Resources section of Item 2. **Cash Flows from Financing Activities—**During the six months ended June 30, 2024, net cash provided by financing activities was primarily the result of the funding of $450 million in First Mortgage Bonds (FMBs) and $78 million in proceeds from the issuance of common stock pursuant to the at-the-market offering program. This was partially offset by $146 million in commercial paper maturities and payment of $96 million of dividends. #### Capital Requirements The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2024 through 2028, excluding AFUDC (in millions): | | 2024 | 2025 | 2026 | 2027 | 2028 | | --- | ---: | ---: | ---: | ---: | ---: | | Ongoing capital expenditures (1) | $915 | $865 | $895 | $890 | $920 | | Transmission | 170 | 180 | 255 | 265 | 435 | | Clearwater | 20 | — | — | — | — | | BESS projects | 235 | 155 | — | — | — | | Total capital expenditures (2) | $1,340 | $1,200 | $1,150 | $1,155 | $1,355 | | Long-term debt maturities | $80 | $— | $— | $160 | $100 | (1) Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connections. Includes accrued capital additions, preliminary engineering, removal costs, and certain intangible working capital assets. (2) Amounts 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. #### 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 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. For 2024, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $700 million to $800 million, and issuances of long-term debt securities of up to $750 million. PGE plans to fund any shortfall through the combination of issuance of common stock and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt, equity, and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments. *Short-term Debt.* Pursuant to an order issued by the FERC in January 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 June 30, 2024 (in millions): | | As of June 30, 2024 Capacity | Outstanding | Available | | --- | ---: | ---: | ---: | | Revolving credit facility (1) | $750 | $— | $750 | | Letters of credit (2) | 320 | 86 | 234 | | Total credit | $1,070 | $86 | $984 | | Cash and cash equivalents | | | 6 | | Total liquidity | | | $990 | (1) Scheduled to expire September 2028. (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. On August 18, 2023, PGE entered into an amendment of its existing revolving credit facility. As of June 30, 2024, 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 remaining term of the applicable credit facility. As of June 30, 2024, PGE had no outstanding balance on the revolving credit facility. The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of June 30, 2024, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $750 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time. *Long-term Debt.* As of June 30, 2024, PGE’s total long-term debt outstanding, net of $15 million of unamortized debt expense, was $4,433 million. On February 22, 2024, PGE entered into a Bond Purchase Agreement related to the sale of $450 million in FMBs. The Bonds were issued and funded in full on February 22, 2024 and consist of: - a series, due in 2029, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 5.15%; - a series, due in 2034, in the amount of $100 million that will bear interest from its issuance date at an annual rate of 5.36%; and - a series, due in 2054, in the amount of $250 million that will bear interest from its issuance date at an annual rate of 5.73%. *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. In 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties. In March 2024, the Company issued 1,714,972 shares pursuant to the agreements and received net proceeds of $78 million. In 2024, PGE entered into additional forward sale agreements with forward counterparties, exhausting the $300 million facility. As of June 30, 2024, these additional agreements were outstanding. The Company could have physically settled the remaining amount by delivering 5,139,501 shares in exchange for cash of $218 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. PGE anticipates entering into a new at-the-market offering program in the third quarter of 2024. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity. For additional information on the at-the-market offering programs, see Note 7, Shareholders’ Equity, in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.” *Capital Structure.* PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company’s common equity ratio was 44.0% and 44.6% as of June 30, 2024 and December 31, 2023 respectively. #### Credit Ratings and Debt Covenants PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows: | | Moody’s | S&P | | --- | --- | --- | | Issuer credit rating | A3 | BBB+ | | Senior secured debt | A1 | A | | Commercial paper | P-2 | A-2 | | Outlook | Negative | Stable | In June 2024, Moody’s revised the Company’s outlook from Stable to Negative. These outlook changes are not expected to have a material impact on the Company’s liquidity or collateral obligations. In the event Moody’s or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits in PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets. As of June 30, 2024, PGE had posted $75 million of collateral with these counterparties, consisting of $55 million in cash and $20 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of June 30, 2024, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $59 million, and decreases to $26 million by December 31, 2024 and to $8 million by December 31, 2025. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $178 million and decreases to $101 million by December 31, 2024 and to $55 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 (Indenture) securing the bonds. PGE estimates that on June 30, 2024, under the most restrictive issuance test in the Indenture, the Company could have issued up to $385 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 under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property. PGE’s revolving credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of June 30, 2024, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 56.7%. ## Market risk As filed, 576 characters. PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company’s market risk or credit risk may affect its future financial position, results of operations, or cash flows. There have been no material changes to market risks, or credit risk, affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 20, 2024. ## Controls and procedures As filed, 846 characters. #### Disclosure Controls and Procedures PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2024, these disclosure controls and procedures were effective. #### Changes in Internal Control over Financial Reporting There were no changes in PGE’s internal control over financial reporting that occurred during the quarter ended June 30, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. ## Risk factors As filed, 209 characters. There have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 20, 2024. Filed Jul 26, 2024. Source: SEC EDGAR, the filing index for accession 0000784977-24-000133. Last ingested by Listed: Oct 29, 2026, 09:00 ET. No prices; not investment advice.