PORTLAND GENERAL ELECTRIC CO /OR/
For the period ended Mar 31, 2025. Filed Apr 25, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2025 · Filed Apr 25, 2025
POR$45.95-0.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2024-09-30; filed 2024-10-25.
0000784977-24-000167
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-04-25.
0000784977-25-000074
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 236 previous paragraphs and 231 current paragraphs.
86 unchanged; 111 reworded; 31 added; 35 removed; 4 previous and 3 current paragraphs rearranged.
Tables are not compared: 21 previous and 21 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (31)
Current report
•the impacts of changes in the tax code, including tax rates, minimum tax rates, adjustments made to deferred tax assets and liabilities, and changes impacting the availability of and ability to transfer renewable tax credits;
Current report
•changes in, compliance with, and general uncertainty around environmental laws and policies;
Current report
•reputational damage from negative publicity, protests, fines, penalties and other negative consequences resulting in regulatory and/or legal actions;
Current report
•physical attacks upon Company employees;
Current report
•acts of war, terrorism, or civil disruption.
Current report
•Constable BESS (formerly Evergreen)—The 75 MW BESS facility, located in Hillsboro, Oregon was placed in service on December 20, 2024 and is owned by PGE. As of March 31, 2025, the Company has recorded $157 million in Electric Utility Plant, net, including AFUDC.
Current report
On December 12, 2024, Project 1 in Group A notified PGE that it was withdrawing from commercial negotiations. PGE continues to negotiate with the remaining Group A projects and aims to finalize contracts over the second half of 2025.
Current report
NewSun was an intervenor in the Clearwater RAC proceeding in Docket UE 427, in which the OPUC rejected NewSun’s proposals to change the RFP oversight process but adopted conditions proposed by OPUC staff on how PGE should recognize Clearwater’s capacity factor and transmission assumptions in its AUT and PCAM beginning in 2025. While PGE is seeking review of the OPUC’s February 21, 2025 order adopting the conditions, PGE cannot predict the outcome or potential impact, if any, on future RFP, AUT, or PCAM proceedings.
Current report
2025 All-Source RFP
Current report
In October 2023, the OPUC accepted PGE’s second TE plan, which covers the 2023 to 2025 time period and considers current and planned activities, along with forecasted EV loads. To date, PGE has incurred $10 million in capital expenditures under the current TE plan. PGE is planning to submit its draft 2026-2028 TE plan in July 2025.
Current report
Trade Tariffs—Recently, trade tariffs were imposed through presidential executive orders. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect. Trade tariffs may increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. For example, the cost of steel utility poles, meters, transformers, and specialized electrical equipment, among other items, may increase materials and supplies balances that are ultimately issued out to capital projects. Similarly, prices may rise for necessary components in resources considered for acquisition in PGE’s All-Source RFPs. For further information on the Company’s RFPs, see “The Resource Planning Process” in the Investing in a Clean Energy Future section of this Overview. While PGE’s Canadian natural gas imports are not expected to be impacted by the current state of trade tariffs due to the imports being U.S.-Mexico-Canada Agreement compliant, the future of trade tariff impacts on such imports is uncertain. The Company is unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, which could include project delays, cost increases, and obstacles to PGE’s strategic plan execution. PGE is closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.
Current report
Colstrip with proposed compliance dates that may not be achievable or require the use of unproven technology, resulting in significant impacts to costs of Colstrip. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively, however a substantial number of legal challenges have been filed regarding these rules. In challenges to all three rules, at the EPA’s request, the courts have granted stays to allow new EPA leadership to reevaluate the rule. In a March 2025 press release, the EPA announced that these rules were among several that the EPA will target for reconsideration. On April 8, 2025, the President issued a proclamation, Regulatory Relief for Certain Stationary Sources to Promote American Energy, granting a two-year compliance exemption pursuant to the CAA Section 112(i)(4) for the Agency’s final rule. The EPA subsequently notified companies whether their sources had been granted the exemption. Colstrip was granted an exemption until July 8, 2029. These challenges, or attempts by the federal government to withdraw or modify the regulations, if successful, could affect the applicability to PGE and Colstrip specifically.
Current report
Given the uncertainty surrounding applicability of these laws and regulations, PGE cannot reasonably estimate the impact to its results of operations, financial position, and cash flows, however, if the MATS Rule and GHG Rule are ultimately enforced, it would likely result in additional material compliance costs. To the extent these regulations result in increased compliance costs, the Company expects to seek recovery of those costs through the ratemaking process.
Current report
Declared states of emergency—The OPUC has approved a pre-authorized deferral of costs associated with qualifying declared states of emergency, which would include federal or state declared emergencies with impacts on PGE’s service territory. Under this mechanism, PGE could provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency, subject to an earnings test. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including a review of utility prudence in a future proceeding, among other requirements.
Current report
PGE believes that the full amount of the deferral is probable of recovery and anticipates submitting a request for recovery early in the third quarter of 2025, with price changes to be effective during 2026. The OPUC has significant discretion in making the final determination of recovery based on its determination of prudency and interpretation of the earnings test application, either of which could result in all, or a portion of, the deferral being disallowed. As of December 31, 2024, PGE's preliminary return on equity, based on actual results, did not exceed the OPUC's authorized rate of return. Any disallowance would be a charge to earnings, which could be material to the Company’s financial condition, results of operations, or cash flows. 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.”
Current report
Reliability Contingency Event (RCE)—Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing power cost adjustment mechanism (PCAM). As of March 31, 2025, PGE’s deferred balance related to RCEs was $95 million, which includes $92 million related to RCEs deferred in 2024 and $3 million related to RCEs deferred in 2025. This includes costs from multiple qualified RCEs during 2024, the most significant of which was related to the January storm event, and costs incurred during the first quarter of 2025. PGE files the results of the PCAM annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective January 1 of the following year. RCE costs incurred in 2024 will be included in the PCAM for 2024, which the Company expects to file no later than July 1, 2025. PGE believes the deferred amounts as of March 31, 2025 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
Current report
Under the RAC, during 2023, the Company submitted a filing in OPUC Docket UE 427 for Clearwater proposing to defer the revenue requirement, net of NVPC benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the twelve month period ending December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits resulting in a net regulatory liability of $40 million, which began amortizing as a refund to customers on March 1, 2025 over a twelve month period, as approved in Order 25-075 issued February 21, 2025. The OPUC’s order also adopted conditions to be applied to the AUT and PGE plans to seek clarification of the applicability of those conditions. For the period of January 1, 2025 through February 28, 2025, PGE deferred an additional net $7 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that PGE believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC for that period. The OPUC has significant discretion on overall prudence and in making the final determination of recovery or refund. Any cost disallowance or increased refunds would be recognized as a charge to earnings.
Current report
New Large Load—In October 2023, in Docket UE 416, the OPUC directed a docket be opened to investigate new load connection costs and in December 2023, the OPUC established Docket UE 430 for that purpose. Following a lengthy regulatory process, in December 2024, PGE filed Advice No. 24-38 with the OPUC. This filing introduces several proposed changes to PGE policies and tariffs that, if approved, would: i) reasonably protect other customers from the cost to connect new large load customers; ii) improve transmission system planning and capacity; iii) provide fair recovery of distribution investment costs from large load users; and iv) implement contractual requirements designed to appropriately allocate and recover distribution and transmission costs and mitigate the risk of stranded assets, while providing flexibility to meet large customer needs.
Current report
On April 15, 2025, the OPUC approved PGE's filing, as revised, with an effective date of April 16, 2025, on condition that the issues raised in the filing would be addressed in a new Commission docket, UM 2377. This allows PGE to begin working with large load customers to form a load interconnection queue, conduct studies to assess and allocate connection costs, and offer study and service agreements. Any agreements with new large load customers may be revised and updated based on the outcome in the separate OPUC proceeding, UM 2377, that was opened to address PGE’s proposed tariff changes and related issues.
Current report
Total retail energy deliveries for the three months ended March 31, 2025 increased 4.6% compared with the three months ended March 31, 2024, driven by an increase in industrial deliveries. The first quarter of 2025 contained one fewer delivery day due to leap year in 2024.
Current report
•For the three months ended March 31, 2024, actual NVPC was $19 million below baseline NVPC. For the year ended December 31, 2024, actual NVPC was $78 million below baseline NVPC, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE was below 10.5%, there was no estimated refund to customers under the PCAM for 2024. A final determination regarding the 2024 PCAM results will be made by the OPUC through a public filing and review in 2025.
Current report
Other operating revenues for the three months ended March 31, 2025 were up $8 million from the comparable period in 2024, primarily the result of an increase in revenues resulting from imbalance transactions with ESS providers.
Current report
For the three months ended March 31, 2025 and 2024, actual NVPC was $6 million and $19 million below baseline NVPC, respectively.
Current report
In the table above, $3 million related to vegetation management, $4 million related to wildfire mitigation, and $4 million related to storm response costs have been offset through customer prices or specific regulatory mechanisms.
Current report
In the table above, $5 million of the decrease in customer related costs is due to regulatory programs that have been offset through customer pricing or specific regulatory mechanisms.
Current report
Interest expense, net increased $5 million in the three months ended March 31, 2025 compared to the same period in 2024, primarily due to higher long-term debt balances.
Current report
Income tax expense increased $9 million in the three months ended March 31, 2025, compared to the same period in 2024, primarily driven by lower PTC benefits resulting from the expiration of the 10-year PTC generation window at Tucannon near the end of 2024.
Current report
•a series, due in 2035, in the amount of $60 million that will bear interest from its issuance date at an annual rate of 5.36%;
Current report
•a series, due in 2045, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 5.72%; and
Current report
•a series, due in 2055, in the amount of $200 million that will bear interest from its issuance date at an annual rate of 5.84%.
Current report
On November 14, 2024, PGE drew a $220 million loan under a 366-day term loan agreement. On December 31, 2024, PGE repaid $50 million of the term loan and, on March 31, 2025, the Company repaid another $102 million, leaving an outstanding balance of $68 million.
Removed paragraphs (35)
Previous report
•changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
Previous report
•acts of war or terrorism.
Previous report
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, the Company 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.
Previous report
•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 September 30, 2024, the Company has recorded$127 million, including AFUDC, in CWIP for the Constable BESS.
Previous report
PGE has begun the process of commercial negotiations and looks to execute final contracts over the course of 2025. The OPUC is scheduled to consider acknowledgement of the RFP shortlist on November 19, 2024 to enable execution of definitive agreements.
Previous report
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 TE.
Previous report
In 2023, PGE’s second 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.
Previous report
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.
Previous report
General Rate Case—On February 29, 2024, PGE filed with the OPUC a General Rate Case (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 net variable power costs (NVPC) projection will be updated periodically during 2024.
Previous report
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.
Previous report
The proposed net increase in annual revenue requirement in the 2025 GRC was based upon a:
Previous report
•capital structure of 50% debt and 50% equity;
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•return on equity of 9.75%;
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•cost of capital of 7.189%; and
Previous report
•rate base of $7.5 billion.
Previous report
PGE and parties continue to work through the 2025 GRC as regulatory review 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.
Previous report
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.
Previous report
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 September 30, 2024, had deferred $45 million, including interest, as a regulatory asset for the costs to repair damage to PGE’s transmission and distribution systems and restore power to customers under the deferral. PGE currently forecasts its preliminary regulated return on equity for the full year 2024 will be in excess of the OPUC’s authorized rate of return that is expected to be used as an earnings test for this deferral. As a result of the earnings test, the Company has decreased the deferral and taken a corresponding charge to earnings for $17 million and, as of September 30, 2024, PGE’s net deferred balance related to the January 2024 storm is $28 million, including interest. PGE will reassess the earnings test, and the related impact to deferred amounts under this mechanism, based on actual return on equity for the year ending December 31, 2024. Actual results experienced by the Company could differ materially from current forecasts and estimates and could increase or decrease the final deferred balance after application of the earnings test. PGE believes the remaining amounts deferred as of September 30, 2024 are probable of recovery under the emergency deferral mechanism. 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.”
Previous report
On July 5, 2024, the Governor of Oregon declared a statewide emergency for a heat wave that engulfed the region. After determining costs resulting from the heat wave, the Company did not record any additional costs under the emergency deferral.
Previous report
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.
Previous report
In the 2022 GRC, parties reached an agreement that eliminated PGE’s decoupling mechanism 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.
Previous report
In the 2024 GRC filing, the Company included a concept proposal to resume decoupling, with certain modifications. PGE then made a tariff filing that proposed weather-normalized decoupling, although at a public meeting in June 2024, the OPUC permanently suspended PGE’s proposed tariff, effectively denying the proposal.
Previous report
Total retail energy deliveries for the nine months ended September 30, 2024 increased 0.3% compared with the nine months ended September 30, 2023, as the increase from industrial customers was nearly offset by decreases in residential and commercial deliveries.
Previous report
For the nine months ended September 30, 2024, milder temperatures have resulted in somewhat lower Total Retail Energy deliveries when compared to the same period of 2023. Total heating degree days have been below the comparable totals for each quarter of 2024 when compared to 2023 and total cooling degree days, were also lower in the second and third quarters of 2024 than 2023.
Previous report
•For the nine months ended September 30, 2023, actual NVPC was $28 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.
Previous report
Net income for the three months ended September 30, 2024 increased $47 million, or 100%, compared to the three months ended September 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, however, were comparable to the same period of 2023, as wholesale energy prices have shown a decline from the same period a year ago. While retail energy deliveries increased period over period as a result of higher demand from industrial customers, the increase in total system load was driven by a rise in wholesale energy deliveries. Generation, transmission and distribution expenses were up due to maintenance activities, vegetation management, service restoration work, and a charge to reduce the deferral for the January 2024 storm due to the application of an earnings test. Depreciation and amortization expense, driven by higher depreciable asset balances, and Interest expense, net, due to higher long-term debt balances, both increased, as anticipated, and were largely offset by increased revenues. Other income, net continues to see higher AFUDC credits in 2024.
Previous report
Other operating revenues for the three months ended September 30, 2024 were up $6 million from the comparable period in 2023. In the nine months ended September 30, 2024, Other operating revenues were up $10 million compared to the same period of 2023, reflecting amortization that is offset in Retail revenues and increased transmission related revenues.
Previous report
For the nine months ended September 30, 2024, the $86 million increase related to the change in average variable power cost per MWh was driven by a 5% increase in the average cost of purchased power and a 18% 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 $151 million increase related to total system load was comprised of an 21% 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.
Previous report
For the three months ended September 30, 2024 and 2023, actual NVPC was $35 million below and $10 million above baseline NVPC, respectively. For the nine months ended September 30, 2024 and 2023, actual NVPC was $87 million below and $28 million above baseline NVPC, respectively.
Previous report
PGE commenced amortization of previously deferred COVID-19 related bad debt expenses on April 1, 2023. For thenine months ended September 30, 2024, the Company amortized $10 million of COVID-19 related bad debt expense that was offset in revenues.
Previous report
Interest expense, net increased $11 million and $29 million, respectively, in the three and nine months ended September 30, 2024 compared to the same periods in 2023, primarily due to higher long-term debt balances.
Previous report
Income tax expense increased $5 million and $1 million, in the three and nine months ended September 30, 2024, respectively, compared to the same periods in 2023, driven by higher pre-tax income partially offset by increased PTC benefits.
Previous report
•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%;
Previous report
•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
Previous report
•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%.
Reworded paragraphs (111)
Previous wording
•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;
Current wording
•governmental policies, executive orders, 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;
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•inflation and volatility in interest rates;
Current wording
•trade tariffs, inflation, and volatility in interest rates;
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•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
Current wording
•risks and uncertainties related to current or future All-Source RFP projects, including, but not limited to regulatory processes, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of trade tariffs), permitting and construction delays, available tax credits, counterparty credit risk, and legislative uncertainty;
Previous wording
•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;
Current wording
•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 financial health and 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;
Previous wording
•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 prices or insurance, resulting in impact to the financial condition, results of operations, or reputation of the Company;
Current wording
•ignitions caused by PGE assets or PGE’s ability to effectively implement a public safety power shut off (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 were involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through prices or insurance, resulting in impact to the financial condition or reputation of the Company;
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•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;
Current wording
•operational factors affecting PGE’s power generating and battery storage facilities, including forced outages, fires, unscheduled delays, environmental impacts, 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;
Previous wording
•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;
Current wording
•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, repair costs, or abandoned costs;
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•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
Current wording
•delays in the supply chain and increased supply costs, failure to complete capital projects on schedule or within budget, failure to obtain permits, 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;
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•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 and other price risk management instruments;
Current wording
•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;
Previous wording
•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;
Current wording
•changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes, including the potential impact of trade tariffs, on the Company’s power costs;
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•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;
Current wording
•capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, volatility of equity markets as well as changes in PGE’s credit ratings, any of which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees;
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•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;
Current wording
•future laws, regulations, and proceedings that could increase the Company’s costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;
Previous wording
•cybersecurity attacks, data security breaches, physical attacks and security breaches, or other malicious acts against the Company or against Company vendors that cause damage to the Company’s facilities or 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;
Current wording
•cybersecurity attacks, data security breaches, physical attacks and security breaches, or other malicious acts, internally or to third parties, 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;
Previous wording
•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;
Current wording
•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 during the COVID-19 pandemic;
Previous wording
•changes in financial or regulatory accounting principles or policies imposed by governing bodies;
Current wording
•changes in financial or regulatory accounting principles or policies imposed by governing bodies; and
Previous wording
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, natural gas, and environmental credits 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).
Current wording
PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State of Oregon (State). The Company participates in wholesale markets by purchasing and selling electricity, natural gas, and environmental credits 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.
Previous wording
State-mandated GHG emissions reduction targets—In 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
Current wording
State-mandated GHG emissions reduction targets—In 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.
Previous wording
Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 230 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.
Current wording
Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 227 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.
Previous wording
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.
Current wording
The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows large business and municipal 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.
Previous wording
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
Current wording
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 make continued progress towards 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.
Previous wording
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 Request for Proposals (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.
Current wording
Throughout the remainder of 2023, PGE refreshed its forecasts, first in an Addendum filed in July 2023 then several times in subsequent comments in the CEP and IRP docket with the OPUC (LC 80). PGE estimates a total resource need of approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to make continual progress towards meeting the Company’s clean energy targets. Through the 2021 All-Source Request for Proposals (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.
Previous wording
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 has continued to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP.
Current wording
On January 25, 2024, the OPUC acknowledged PGE’s IRP, subject to certain conditions, providing regulatory support for the Company to pursue the near-term resource additions articulated in the Action Plan. However, the OPUC declined to acknowledge the CEP, directing the Company to provide additional forecast of its emission reductions based on new analysis in the CEP/IRP Update to be filed in June 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP.
Previous wording
•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 facility was placed in-service during the first quarter of 2024. As of September 30, 2024, the Company has recorded $418 million in Electric Utility Plant, net, including Allowance for funds used during construction (AFUDC).
Current wording
•Clearwater Wind Development (Clearwater)—The 311 MW wind energy facility is part of the larger Clearwater Wind Development 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.
Previous wording
•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 September 30, 2024, the Company has recorded $165 million, including AFUDC, in construction work-in-progress (CWIP) for the Seaside Grid.
Current wording
•Seaside Grid—The 200 MW Battery Energy Storage System (BESS) facility, located in Portland, Oregon has an estimated commercial operation date of June 30, 2025 and will be owned by PGE. As of March 31, 2025, the Company has recorded $334 million, including AFUDC, in construction work-in-progress (CWIP) for the Seaside Grid.
Previous wording
•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.
Current wording
•Sundial BESS (formerly Troutdale Grid)—The 200 MW BESS facility, located in Troutdale, Oregon reached commercial operations on December 20, 2024. NextEra Energy Resources, LLC owns the resource and sells the capacity to PGE under a 20-year agreement.
Previous wording
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.
Current wording
The agreements related to the Clearwater Wind Development 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.
Previous wording
All BESS facilities will be directly interconnected to PGE’s transmission and distribution system. In the event emissions are associated with energy obtained to charge the BESS, they are accounted for when they are emitted from the generating facility. As such, BESS facilities do not add incremental emissions to the grid, and therefore, are non-emitting dispatchable capacity resources. The BESS facilities 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.
Current wording
All BESS projects will be directly interconnected to PGE’s transmission and distribution system. In the event emissions are associated with energy obtained to charge the BESS, they are accounted for when they are emitted from the generating facility. As such, BESS projects do not add incremental emissions to the grid, and therefore, are considered non-emitting dispatchable capacity resources. The BESS facilities qualify for the federal investment tax credits (ITCs). The agreements related to the Clearwater Wind Development 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.
Previous wording
PGE constructed the final short list to provide optionality and address the Company’s future capacity need. The Company ranked the final shortlist in two groups, prioritized based on performance in the RFP price scoring evaluation, representing the optimal intersection of value to customers at the least-cost and the least-risk. These two groups together represent the final shortlist of projects recommended for regulatory acknowledgement, as follows:
Current wording
PGE constructed the final short list to provide optionality and address the Company’s future capacity need. The Company ranked the final shortlist in two groups, prioritized based on performance in the RFP price scoring evaluation, representing the optimal intersection of value to customers at the least-cost and the least-risk. These two groups together represented the final shortlist of projects recommended for regulatory acknowledgement. On November 19, 2024, the OPUC acknowledged, with conditions, PGE’s final shortlist of resources as follows:
Previous wording
•Group A, as shown below, now consists of three bids that are top performing and PGE expects to enter commercial negotiation for all of these projects. Group A includes 375 megawatts (MW) nameplate of renewable resources and 400 MW nameplate of battery storage; and
Current wording
•Group A, as shown below, consisted of three bids that are top performing and PGE expected to enter commercial negotiation for all of these projects. Group A included 375 megawatts (MW) nameplate of renewable resources and 400 MW nameplate of battery storage; and
Previous wording
•Group B, as shown below, consists of five bids, all of which represent capacity options via BESS facilities. These projects are also high performing and PGE may enter commercial negotiations with some or all of these projects, allowing flexibility to address any remaining capacity need. Group B includes 885 MW nameplate of battery storage.
Current wording
•Group B, as shown below, consisted of five bids, all of which represent capacity options via BESS facilities. These projects are also high performing and PGE may enter commercial negotiations with some or all of these projects, allowing flexibility to address any remaining capacity need. Group B includes 885 MW nameplate of battery storage.
Previous wording
Both the 2021 and 2023 RFPs are the subject of regulatory and legal challenges initiated by NewSun Energy LLC, focused on the scoring methodology of the RFPs and OPUC acknowledgement of the final shortlists. PGE has joined these proceedings as an intervenor, and the challenges are in various stages of litigation or regulatory review. PGE cannot predict the outcome of these proceedings or potential impact, if any, to either its 2021 or 2023 All-Source RFP processes.
Current wording
Both the 2021 and 2023 RFPs were the subject of regulatory and legal challenges initiated by NewSun Energy LLC, focused on the scoring methodology of the RFPs and OPUC acknowledgement of the final shortlists. Two of NewSun’s challenges to the 2021 RFP were dismissed as moot in recent court decisions, although NewSun has indicated it will file further appeals. PGE has joined the proceedings as an intervenor, and the remaining challenges are in various stages of litigation or regulatory review. PGE cannot predict the outcome of these proceedings or potential impact, if any, on its 2021 and 2023 All-Source RFP process.
Previous wording
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, increase access to renewable generation, and address growing customer demand.
Current wording
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.
Previous wording
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 have entered negotiations with the U.S. DOE to finalize the project objectives, terms, and conditions, including the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. On August 6, 2024, the project was awarded a $700 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships program to further support its development and would reduce the overall total investment of the project.
Current wording
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 have entered negotiations with the United States Department of Energy (U.S. DOE) to finalize the project objectives, terms, and conditions, including the Company’s participation, which is expected to involve a 20% ownership share of the approximately $3.2 billion total investment of the project. On August 6, 2024, the project was awarded a $700 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) program to further support its development and would reduce the overall total investment of the project. A portion of the GRIP funding is allocated to assess upgrades to the Colstrip Transmission System. See “Federal Grants” in this Overview for further discussion over the impacts of Federal grants and effect of Presidential executive orders.
Previous wording
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, and enhanced wholesale markets, and ease congestion on the existing western transmission system.
Current wording
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. PGE's resource planning process indicates the need for transmission to provide additional transfer capacity, access to diverse energy resources, access to enhanced wholesale markets, and ease congestion on the existing western transmission system. PGE continues to explore the North Plains Connector as a resource to meet those load-service needs.
Previous wording
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 communities by increasing resources available to CTWS to support adaptation and response strategies. See“Federal Grants” in this Overview for further discussion.
Current wording
The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS) with PGE as a subrecipient under the grant, 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 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 communities by increasing resources available to the CTWS to support economic growth opportunities. See“Federal Grants” in this Overview for further discussion over the impacts of Federal grants and the potential effect of Presidential executive orders.
Previous wording
•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 nine months ended September 30, 2024, PGE invested $30 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2024 WMP.
Current wording
•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 2025 WMP Update forecasts $53 to $57 million in operations and maintenance costs and an additional $57 to $78 million in capital investments, for the year ending 2025, 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 mitigating the risk that PGE’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the three months ended March 31, 2025, PGE invested $8.5 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2025 WMP.
Previous wording
•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 flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) 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. Customer participation in the VPP helps avoid customer service interruptions and reduces exposure to scarcity pricing in energy markets. On August 14, 2023, customer actions, orchestrated through the VPP, reduced load by more than 90 MW. On July 8, 2024, increased participation reduced load by more than 100 MW. As their participation in PGE’s VPP grows, customer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.
Current wording
•Virtual Power Plant (VPP)—PGE’s VPP is comprised of Distributed Energy Resources and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to flexible load programs, rooftop solar, battery storage, and electric vehicle (EV) charging solutions support grid reliability and increase portfolio flexibility and resource diversity. These Distributed Energy Resources and flexible loads are the foundation of PGE’s VPP that increasingly provides a growing suite of grid and system services over time. When coordinated through the Company’s Distributed Energy Resources Management Systems, Distributed Energy Resource 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. Customer participation in the VPP helps avoid customer service interruptions and reduces exposure to scarcity pricing in energy markets. On July 8, 2024, customer actions, orchestrated through the VPP, reduced load by more than 100 MW. As their participation in PGE’s VPP grows, customer actions provide increasing benefit and help avoid customer service interruptions and reduce exposure to scarcity pricing in energy markets.
Previous wording
•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 finalizes their review of potential modifications to 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 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.
Current wording
•Distribution System Plan (DSP)—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. The OPUC Staff finalized their review of modifications to the current DSP guidelines in the fourth quarter of 2024 and PGE filed its next DSP in December 2024, fully compliant with the updated requirement. The DSP outlines distribution system assets, describes how the Company plans for new load, including distributed resources such as EVs and rooftop solar installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in meeting PGE’s clean energy goals.
Previous wording
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.
Current wording
Electrify the economy—To help Oregon reach its decarbonization goals, PGE is committed to increasing electrification of buildings and supporting vehicle electrification for customers, as well as its own vehicle fleet.
Previous wording
Transportation electrification (TE) 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 EV charging stations, build fleet partnerships, and offer programs to encourage customers to advance transportation electrification.
Current wording
Transportation electrification (TE) 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 EV charging stations, build electric fleet partnerships, and offer programs to support customers’ transitions to TE.
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Current report — wording carried from elsewhere
PGE filed notice with the OPUC in November 2024 that an RFP in 2025 was needed to procure resources to meet a forecasted 2029 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 2025 All-Source RFP on April 17, 2025.
Current report — wording carried from elsewhere
•U.S. DOE Grid Edge Devices—The U.S. DOE selected and subsequently entered into an agreement on October 1, 2024 with PGE leading a consortium for a $50 million grant for the Grid Edge Devices project.
Current report — wording carried from elsewhere
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 securing inventory of critical materials to improve reliability, reserving manufacturing capacity with strategic partners, and evaluating availability with established and new suppliers. The Company’s materials and supplies forecasting process is designed to secure materials availability as well as mitigate cost increases through long-term agreements, supplier engagement, and expanding the supply base. PGE is monitoring the fluid situation around tariffs and trade policies and continues to evaluate any potential impact to its operations and the need to implement applicable mitigation strategies.
Rearranged previous paragraphs (4)
Previous report — wording carried elsewhere
Company’s inability to recover project costs or impact PGE’s competitive position, market share, or results of operations in a material way;
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
20 years and proposed an Action Plan to meet near-term needs, subject to the HB 2021 emissions reduction requirements.
Previous report — wording carried elsewhere
On July 26, 2024, PGE entered into an equity distribution agreement under which it could sell up to $400 million of its common stock through at the market offering programs. As of September 30, 2024, the Company had not yet transacted under this program. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.