PORTLAND GENERAL ELECTRIC CO /OR/ - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.
- Jul 28, 2022 2:15 pm GMT
The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions, and objectives concerning future results of operations, business prospects, loads, outcome of litigation and regulatory proceedings, capital expenditures, market conditions, future events or performance, and other matters. Words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," "should," or similar expressions are intended to identify such forward-looking statements. Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE's expectations, beliefs, and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, but not limited to, management's examination of historical operating trends and data contained either in internal records or available from third parties, but there can be no assurance that PGE's expectations, beliefs, or projections will be achieved or accomplished.
In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:
•governmental policies, legislative action, and regulatory audits, investigations, and actions, including those of the
Federal Regulatory Energy Commission(FERC), the Public Utility Commission of Oregon, (OPUC), the Securities and Exchange Commission(SEC), and the Division of Enforcementof the Commodity Futures Trading Commission(CFTC) with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs, and capital investments, energy trading activities, and current or prospective wholesale and retail competition;
•economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers, and elevated levels of uncollectible customer accounts;
•inflation and interest rates;
•changing customer expectations and choices that may reduce customer demand for its services may impact PGE's ability to make and recover its investments through rates and earn its authorized return on equity, including the impact of growing distributed and renewable generation resources, changing customer demand for enhanced electric services, and an increasing risk that customers procure electricity from registered Electricity Service Suppliers (ESSs) or community choice aggregators; •the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described under the heading of Regulatory Matters in the Overview section of this Item 2, and Note 8, Contingencies in the Notes to the Condensed Consolidated Financial Statements 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;
•unseasonable or extreme weather and other natural phenomena, such as the greater size and prevalence of wildfires in
35 -------------------------------------------------------------------------------- Table of Contents PGE's ability and cost to procure adequate power and fuel supplies to serve its customers, PGE's ability to access the wholesale energy market, PGE's ability to operate its generating facilities and transmission and distribution systems, the Company's costs to maintain, repair, and replace such facilities and systems, and recovery of costs; •PGE's ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk, which could cause damage to the Company's own facilities or lead to potential liability if energized systems are involved in wildfires that cause harm; •operational factors affecting PGE's power generating facilities and battery storage facilities, including forced outages, unscheduled delays, hydro and wind conditions, and disruption of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;
•default or nonperformance on the part of any parties from whom PGE purchases capacity or energy, which may cause the Company to incur costs to purchase replacement power and related renewable attributes at increased costs;
•complications arising from PGE's jointly-owned plant, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs; •delays in the supply chain and increased supply costs, failure to complete capital projects on schedule or within budget, failure of counterparties to perform under agreements, or the abandonment of capital projects, any of which could result in the Company's inability to recover project costs, or impact PGE's competitive position, market share, or results of operations in a material way; •volatility in wholesale power and natural gas prices that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements;
•changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company's power costs;
•capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, volatility of equity markets as well as changes in PGE's credit ratings, any of which could have an impact on the Company's cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, the repayments of maturing debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees; •future laws, regulations, and proceedings that could increase the Company's costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;
•changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;
•the effects of climate change, whether global or local in nature, including unseasonable or extreme weather and other natural phenomena that may affect energy costs or consumption, increase the Company's costs, cause damage to PGE facilities and system, or adversely affect its operations;
•changes in residential, commercial, or industrial customer demand, or demographic patterns, in PGE's service territory;
•the effectiveness of PGE's risk management policies and procedures;
•cybersecurity attacks, data security breaches, physical security breaches, or other malicious acts that cause damage to the Company's generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, employee, or Company information;
36 -------------------------------------------------------------------------------- Table of Contents •employee workforce factors, including potential strikes, work stoppages, transitions in senior management, the ability to recruit and retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries since the beginning of the coronavirus (COVID-19) pandemic;
•new federal, state, and local laws that could have adverse effects on operating results;
•failure to achieve the Company's greenhouse gas emission goals or being perceived to have either failed to act responsibly with respect to the environment or effectively responded to legislative requirements concerning greenhouse gas emission reductions, any of which could lead to adverse publicity and have adverse effects on the Company's operations and/or damage the Company's reputation;
•political and economic conditions;
•the impact of widespread health developments, including the global COVID-19 pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities), which could materially and adversely affect, among other things, demand for electric services, customers' ability to pay, supply chains, personnel, contract counterparties, liquidity and financial markets;
•changes in financial or regulatory accounting principles or policies imposed by governing bodies;
•acts of war or terrorism; and
•risks and uncertainties related to 2021 All-Source RFP final shortlist projects, including, but not limited to regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including application of tariffs impacting solar module imports), and legislative uncertainty.
Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. The MD&A should be read in conjunction with the Company's condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the
United States Securities and Exchange Commission(SEC). PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the State of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company also performs portfolio management and wholesale market sales services for third parties in the region. PGE is committed to developing products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.
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 37 -------------------------------------------------------------------------------- Table of Contents with customers, communities, policy makers, and other stakeholders to deliver affordable, safe, reliable electricity service to all, while increasing opportunities to deliver clean and renewable energy, reducing greenhouse gas emissions, and responding to evolving customer expectations. At the same time, the Company is building an increasingly smart, integrated, and interconnected grid that spans from residential customers to other utilities within the region. PGE is transforming all aspects of its business to empower its workforce to be even more results oriented to serve customers well. To create a clean energy future, PGE is focused on the following strategic initiatives:
•Decarbonize the power supply by reducing greenhouse gas (GHG) emissions associated with the power served to customers in-line with the GHG reduction targets set by Oregon House Bill (HB) 2021, ultimately achieving zero GHG emissions associated with the power served to customers by 2040;
•Electrify other sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and
•Perform by improving work efficiency, safety of its workforce, and reliability of its systems and equipment, all while adhering to the Company's long-term earnings per diluted share growth guidance of 4-6% on average.
State-mandated GHG reduction targets-In
June 2021, the Oregonlegislature passed HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the state. A number of provisions in the bill align with PGE's strategic direction, and highlight Oregon'sambitious, economy-wide goals to combat climate change. The GHG reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see the "Environmental Laws and Regulations" section within this Overview. Empowering customers and communities-PGE's customers are committed to purchasing clean energy, as over 232 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'smost populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE's service area have similar goals and continue to consider similar goals for the future. The Company implemented a customer subscription option, the Green Future Impact Program, which is a renewable energy program that allows customers to have a choice in how they source their electricity. Under the Green Future Impact Program, customers can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option (PSO). Under the CSO, participants are responsible for finding a renewable energy facility that meets established requirements and bringing those resources to PGE. Under the PSO, customers who enrolled in Phase I can receive energy from PGE-provided purchased power agreements (PPAs) for renewable resources and customers who enroll in Phase II can receive energy from PGE-provided PPAs for renewable resources or energy from renewable resources that are PGE owned, under certain conditions. As of June 30, 2022, the Green Future Impact Program has an approved capacity of 750 Megawatts (MW) nameplate. Through this voluntary program, the Company seeks to support the customers' clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power. Extreme weather-In recent years, PGE's territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. In June 2021, temperatures in the region reached all-time recorded highs, shattering the Company's previous peak load demand, and surpassing the prior summer peak load by nearly 12%. The 2021 wildfire season that followed in Oregonproduced what became the largest wildfire in the United Statesat the time. In February 2021, PGE's service territory experienced an ice storm, which led to historic levels of customer power outages, and caused considerable expense for service restoration and damage repair (see " February 2021Ice Storms and Damage" in the "Regulatory Matters" section of this Overview for more information on the impact to PGE's 38 -------------------------------------------------------------------------------- Table of Contents results of operation). In 2020, Oregonexperienced the most destructive wildfire season on record, with over one million acres of land burned (see "Wildfire" in the "Regulatory Matters" section of this Overview for more information on the impact to PGE's results of operation). The increase and severity of extreme weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.
Investing in a clean energy future
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 will prepare a Clean Energy Plan (CEP), which will articulate the Company's strategy to meet the 2030 and 2040 decarbonization targets. The first CEP is anticipated to be filed with the OPUC in the Spring of 2023 and will set annual decarbonization targets and articulate how PGE will achieve an equitable transition to a decarbonized grid. PGE's resource planning analysis and stakeholder engagement will continue to occur through the Integrated Resource Plan (IRP) and Distribution System Plan (DSP) processes. In
May 2020, PGE obtained an OPUC Order acknowledging the Company's 2019 IRP and associated Action Plan for PGE to acquire resources over the next four years, an important step in acquiring the necessary clean and renewable and capacity resources needed to meet requirements under HB 2021 by 2030. In October 2021, PGE initiated its 2021 All-Source RFP public process, seeking approximately 1,000 MW of renewable and non-emitting resources. PGE estimates that the 2021 All-Source RFP will meet a portion of the Company's projected need of approximately 2,500 to 3,500 MW of clean and renewable resources and approximately 800 to 1,000 MW of non-emitting dispatchable capacity resources in order to meet the Company's 2030 emissions reduction target. These projections will be further evaluated and refined in the next IRP and CEP. PGE also expects it will need to exit Colstripand is actively working on plans to achieve this by the end of 2025.
The 2021 All-Source RFP seeks:
•Approximately 375 to 500 MW of renewable resources;
•Approximately 375 MW of non-emitting dispatchable capacity resources that can be used to meet peak customer demand; and
•One or more resources for the Company's Green Future Impact Program. Under the Green Future Impact Program, PGE plans to acquire up to 100 MW of new wind, solar, or hybrid renewable and battery storage resources to meet subscriber demand under the PGE supply option. The Company expects the Green Future Impact Program resources considered in the 2021 All-Source RFP to be incremental to the 150 MWa renewable energy target envisioned under the 2019 IRP Action Plan. On
July 14, 2022, the OPUC directed PGE to seek additional renewable procurement volumes beyond 150 MWa provided adequate resources remain commercially available as part of the 2021 All-Source RFP. Specifically, the OPUC directed PGE to seek 250 MWa of renewable procurement volume inclusive of the 100 MW Green Future Impact procurement volume. Renewable resources in PGE's 2021 All-Source RFP must be eligible under Oregon'sRenewable Portfolio Standard (RPS) and qualify for the federal production tax credit (PTC) or the federal investment tax credit. All resources (dispatchable capacity or renewable) must be online by the end of 2024, with certain exceptions for long-lead time resources. PGE issued the final 2021 All-Source RFP after receiving approval with modifications from the OPUC in December 2021, and proposals were submitted in January 2022. Bids were evaluated based on the OPUC-approved scoring methodology. Following determination of a final shortlist, PGE submitted a request for acknowledgement of the shortlist to the OPUC on May 5, 2022that includes seven distinct projects submitted by five bidders for renewable resources and six distinct projects by four bidders for capacity resources. 39 -------------------------------------------------------------------------------- Table of Contents The proposals for renewable resources provide various combinations of wind, solar, and battery storage options that include PPAs along with Company-owned resources. The proposals for non-emitting capacity resources provide battery storage and pumped storage options that include PPAs along with Company-owned resources. The ultimate outcome of the 2021 All-Source RFP process may involve the selection of multiple projects for both renewable and capacity resources. On July 14, 2022, the OPUC acknowledged, subject to additional conditions or directives that may be issued in the final order, PGE's proposed final shortlist to procure approximately 250 MWa of renewable resources and sufficient non-emitting dispatchable capacity to meet the 2025 system need. 2021 All-Source RFP final shortlist projects were evaluated and selected based on conditions as of the shortlist date. PGE intends to finalize negotiations prior to the end of 2022 to allow sufficient time to capture expiring federal tax credits for the benefit of customers. In February 2022, NewSun Energy LLC("NewSun") filed a petition for judicial review in the Marion County Circuit Courtagainst the OPUC challenging the scoring methodology in the 2021 All-Source RFP. PGE has 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 2022by filing a notice of appeal with the Court of Appeals of the State of Oregon. PGE cannot predict the outcome of the proceeding or potential impact, if any, to its ongoing 2021 All-Source RFP process. In October 2021, PGE filed its inaugural Distribution System Plan (DSP), which lays out plans to build a grid that empowers customers to make energy management choices to support decarbonization and supports a two-way energy ecosystem with resources like batteries, EV charging, and solar panels where communities-especially underserved Oregonians-need them. The plan consists of two parts, the first of which was acknowledged by the OPUC on March 8, 2022. Part Two is expected to be filed in August 2022.
Electrify the economy-To help
Oregonreach its decarbonization goals, PGE is working to build a safe, reliable, and affordable, economy-wide, clean energy future. The Company is committed to increase electrification of buildings and support the accelerating pace of vehicle electrification. Transportation electrification is one of the most significant ways to reduce GHG emissions in Oregon. PGE is engaged with customers and communities to develop infrastructure projects aimed at improving accessibility to electric vehicle charging stations, build fleet partnerships, and offer programs to encourage customers to advance transportation electrification. In 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to Oregon'scarbon reduction goals. In 2020, the OPUC accepted the plan and related costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. In 2021, the Oregonlegislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification. Businesses and families continue to turn to electricity to serve their home and workplace needs and PGE continues to share information on the benefits of electric appliances, landscaping tools and equipment, and heat pumps, which provide efficient heating and cooling. In addition, the Company continues to pursue advanced technologies to enhance the grid, pursue distributed generation and energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs. 40 -------------------------------------------------------------------------------- Table of Contents Environmental Laws and Regulations HB 2021-In June 2021, the Oregon Legislaturepassed HB 2021, which requires retail electricity providers to reduce GHG emissions associated with serving Oregonretail electricity consumers by 80% by 2030, 90% by 2035, and 100% by 2040, compared to their baseline emissions levels. The baseline emissions levels for the investor-owned utilities are the average annual GHG emissions for the years 2010, 2011, and 2012 associated with the electricity sold to their retail electricity consumers as reported to the Oregon Department of Environmental Quality(ODEQ). HB 2021 requires utilities to develop a CEP for meeting the targets concurrent with the development of each IRP. In reviewing the CEP, the OPUC must ensure that utilities demonstrate continual progress and are taking actions as soon as practicable that facilitate rapid reduction of GHG emissions and the transition to an equitable grid at reasonable costs to retail electricity consumers. The OPUC is also given authority to apply a performance incentive for early compliance with one or more of the clean energy targets. Regulated entities will continue to report annual GHG emissions to ODEQ, as they do today. In threshold years, which are 2030, 2035, and 2040 and every year thereafter, the OPUC will use the data reported to ODEQ for that compliance year to determine whether the reduction targets are met. In determining compliance, if the utility has emissions in excess of the target, the OPUC must take into consideration unplanned emissions necessary to meet load if the utility experienced unexpected challenges, such as transmission constraints or under-production from hydro and other renewable resources. The bill also includes certain compliance exceptions to protect customers, including a cost cap and the ability for the OPUC to grant a temporary exemption if a utility is unable to comply with mandatory reliability standards.
HB 2021 also:
•Aligns with PGE decarbonization goals while protecting affordability and reliability;
•Establishes clear decarbonization authority for the OPUC, including authority over ESSs;
•Modernizes competition provisions of
•Provides clear authority and process for a community-wide green tariff program for customers 30 kilowatts and smaller and allows utilities the ability to earn a return on investments in program resources; and
•Codifies non-bypassability of costs to ensure all customers pay their share of HB 2021 policy costs.
Governor Executive Orders-In 2020, the Governor of
Oregonissued an executive order that directed state agencies to integrate climate change and the State's GHG emissions reduction goals into their plans, budgets, investments, and decisions to the extent allowed by law. Among other things, the executive order directed the OPUC to:
•encourage electric companies to support transportation electrification infrastructure that supports GHG emissions reductions and zero-emission vehicle goals;
•prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy; and
•determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with
In addition, the executive order directed the ODEQ to adopt a program to cap and reduce GHG emissions within the state from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas. The ODEQ adopted such a program, referred to as the Climate Protection Plan (CPP), in
December 2021. Electricity 41
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generation from the Company's natural gas-fired resources is exempt from the CPP. The executive order also strengthened the reduction goals of the State's Clean Fuels Program and extended the program, from the previous rule that required a ten percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035. PGE continues to monitor activities of state agencies that have utilized the executive order to shape state policy or seek to implement the order through their own regulatory authority. RPS Standards and Other Laws-In 2016,
OregonSenate Bill 1547 (SB 1547) set a benchmark for how much electricity must come from renewable sources and required the elimination of coal from Oregonutility customers' energy supply no later than 2030.
Other provisions of the law include:
•An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;
•A limitation on the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before
December 31, 2022; and
•An allowance for energy storage costs related to renewable energy in the Company's Renewable Adjustment Clause (RAC) filings.
In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE's investment in
Colstripfrom 2042 to 2030. In 2020, the owners of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has no direct ownership interest in those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2. Effective May 9, 2022, PGE's depreciation rates and customer collection changed to reflect accelerated depreciation of Colstrip Units 3 and 4 from December 31, 2030to December 31, 2025. PGE expects a major step toward meeting its goals under HB 2021 involves the need to exit Colstripand is actively working on plans to achieve this by the end of 2025. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of PGE's exit from the generation facility. See Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements" for information regarding legal proceedings related to Colstrip. Any reduction in generation from Colstriphas the potential to provide capacity on the Colstrip Transmission facilities, which stretch from eastern Montanato near the western end of that state to serve markets in the Pacific Northwestand neighboring states. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities.
PGE focuses on providing reliable, clean power to customers at affordable prices while providing a fair return to investors. To achieve this goal the Company must execute effectively within its regulatory framework and maintain prudent management of key financial, regulatory, and environmental matters that may affect customer prices and investor returns. The following discussion provides detail on such matters.
General Rate Case-In July 2021, PGE filed with the OPUC a GRC based on a 2022 test year. The net price increase and annual revenue requirement included a price increase as a result of higher net variable power costs (NVPC) expected in 2022, as reflected in the Annual Power Cost Update Tariff (AUT) filed with the OPUC in April 2021. 42
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PGE, OPUC staff, and certain customer groups reached an agreement that resolved cost of capital issues and allowed for:
•A capital structure of 50% debt and 50% equity;
•A return on equity of 9.5%; and
•A cost of capital of 6.83%, which reflects updates for actual and forecasted debt costs.
In addition, parties filed a stipulation with the OPUC reflecting an agreement that resolved the annual revenue requirement, average rate base, and corresponding increase authorized in customer prices. The stipulated agreement reflected a final revenue requirement that was based upon an average rate base of
$5.6 billionand an annual revenue requirement increase of $74 millionconsisting of the following changes (in millions): As filed (includes $40 millionrelated to NVPC) $ 99Load and NVPC Updates 16
Base Business Revenue Requirement Updates:
Faraday hydro capital-related revenue requirement (1) $
Cost of debt settlement including reductions to reflect actual financing costs
Level III outage annual regulatory accrual (2)
Other reductions to rate base and operating and maintenance expenses
(5) Other various modifications to reflect actual costs (4) Subtotal (41) As revised (includes
$64 millionrelated to NVPC) (3) $ 74(1) The Faraday improvement capital project was not placed in-service as of May 9, 2022, and the capital-related revenue requirement was removed. As of June 30, 2022, the construction work-in-progress balance associated with Faraday was $127 million, including an allowance for funds used during construction (AFUDC). (2) PGE is authorized to collect annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In the 2022 GRC, the Company requested an annual collection increase from $4 millionto $11 million, and agreed to retain the annual collection at $4 million.
(3) Total revenue requirement increase to base rates is
Further, the parties agreed to eliminate PGE's decoupling mechanism upon the effective date of new customer prices pursuant to this case. Throughout the remainder of 2022, estimated collections from, or refunds to, customers will be pro-rated based on the effective date of new customer prices per the 2022 GRC and expected to be amortized in customer prices in 2024 over a one-year period. The decoupling mechanism provided a means of recovery or refund of margin lost or gained as a result of changes in weather-adjusted energy use per customer in comparison to levels projected in customer prices. For further information on the decoupling mechanism, see "Decoupling" in this Overview section. On
April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism. New customer prices as approved by the OPUC became effective May 9, 2022. Price changes for the AUT and items under other supplemental schedules occurred January 1, 2022. Key elements of the OPUC's Order also included:
•establishment of a balancing account for the Company's major storm damage recovery mechanism;
•denial of PGE's proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project. PGE can pursue recovery in the Company's next GRC; 43
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•establishment of a deferral that would require PGE to defer and refund, subject to an earnings test, the revenue requirement associated with Boardman included in customer prices following plant closure in 2020 (for more information see "Deferral of Boardman Revenue Requirement" within this "Overview" section); and
•creation of an earnings test for the deferrals for the 2020
Complete details of the 2022 GRC filing (OPUC Docket UE 394) and the resulting OPUC Order are available on the OPUC Internet website at www.oregon.gov/puc.
As a result of the earnings tests outlined in the OPUC's Order, the Company released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended
March 31, 2022in the amount of $17 million. The amount recorded represents the Company's estimate based on its interpretation of the OPUC's earnings test. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no release of deferrals or earnings test reserve is expected for 2021 and 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances compared to the amount reserved by the Company as of June 30, 2022, which could be material. COVID-19 Impacts-The COVID-19 pandemic has had a variety of adverse impacts on economic activity. The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. As a result of these activities and economic hardships, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs. In March 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC's jurisdiction, intervenors, and OPUC Staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114. The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent to the timing of recovery of such costs. In September 2020, the OPUC adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE's deferral application was approved by the OPUC in October 2020with final stipulations for the Term Sheet approved in November 2020. As of June 30, 2022and December 31, 2021, PGE's deferred balance was $34 millionand $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. Based on the Term Sheet, PGE expects to cease deferring incremental bad debt expense associated with customers who are not on a time payment arrangement, after September 30, 2022. The Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022in the amount of $2 million. The amount recorded represents the Company's estimate based on its understanding of the OPUC's intent to apply an earnings test to certain elements of utility COVID deferrals. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings review. PGE believes the amounts deferred are probable of recovery as the Company's prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. 44
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Labor DayWildfire-In 2020, Oregonexperienced the most destructive wildfire season on record, with over one million acres of land burned. PGE's wildfire mitigation planning includes regular system-wide risk assessment, which led to the identification and activation of a PSPS in a zone near Mt. Hoodthat was identified as a region at high risk of wildfire in 2020. Additionally, in response to wildfires across Oregonin 2020, PGE cut power to eight additional high-risk fire areas in partnership with local and regional agencies. The Oregon Department of Forestryhas opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment. In October 2020, the OPUC formally approved PGE's request for deferral of 2020 wildfire-related costs. As of June 30, 2022and December 31, 2021, PGE's cumulative deferred costs related to the 2020 wildfire response was $30 millionand $45 million, respectively. Pursuant to the earnings tests outlined in Order 22-129, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022in the amount of $15 million. The amount recorded represents the Company's estimate based on its interpretation of the OPUC's earnings test. Wildfire Mitigation-Represents incremental costs and investments made by PGE related to intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises under OregonSenate Bill 762 (SB 762), which was passed in the 2021 legislative session with an effective date of July 19, 2021. These efforts include enhanced tree and brush clearing, replacing equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. Pursuant to SB 762, PGE submitted a risk-based wildfire protection plan to the OPUC in December 2021. In Order 22-129, the OPUC did not adopt any rate adjustment mechanisms, but rather invited PGE to submit a filing proposing a cost recovery mechanism for incremental wildfire costs consistent with SB 762 and establishing an ongoing review for reasonableness. The outcome of PGE's 2022 GRC provided an annual amount of $24 millionto be collected in customer prices in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in customer prices. As of June 30, 2022, PGE's deferred balance related to wildfire mitigation was $20 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusions of overall prudence, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
The Company's deferral application for expenses related to wildfire mitigation, filed in 2019 under OPUC Docket UM 2019, has not yet been approved by the OPUC.
February 2021Ice Storms and Damage-In February 2021, a historic set of storms involving heavy snow, winds and ice impacted the United States, including PGE's service territory. Oregon'sGovernor declared a state of emergency due to severe winter weather that resulted in heavy snow and ice accumulation, high winds, critical transportation failures, and loss of power and communications capabilities. The wind and ice from the storms caused significant damage to PGE's transmission and distribution systems, which resulted in over 750,000 outages, with many customers affected more than once. At peak activity during the recovery, PGE deployed over 400 repair crews across the service territory, with many of these crews provided through mutual aid arrangements from throughout the West. On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) and as of June 30, 2022, the Company has deferred a total of $72 million, including interest, related to incremental operating expenses due to the storms. PGE incurred and deferred costs related to replacing and rebuilding PGE facilities damaged by the storms, as well as addressing vegetation and other resulting debris and hazards both in and outside of PGE's property and right-of-way. PGE received OPUC Order No. 22-020 approving the February storms deferral in the first quarter of 2022. While the Company believes the full amount of the deferral is probable of recovery given PGE's prudently incurred costs were in response to the unique 45 -------------------------------------------------------------------------------- Table of Contents and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusion of overall prudence, including an earnings test, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. Declared states of emergency-In September 2021, the OPUC issued an order that approved a pre-authorized deferral of costs associated with declared states of emergency. Qualifying events would include federal or state declared emergencies with impacts on PGE's service territory. Previously the Company had to file a request for deferred accounting when an event of that nature occurred, and had to seek OPUC approval of such deferred accounting applications to be effective. With this order, PGE would provide notice of an event that qualifies within 30 days of the declared state of emergency and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the emergency. 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. PGE has not recorded any costs under this deferral order. Power Costs-Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2022 AUT included a final increase in power costs for 2022, and a corresponding increase in annual revenue requirement, of $64 millionfrom 2021 levels, which were reflected in customer prices effective January 1, 2022. For 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the Company's power cost adjustment mechanism (PCAM) and related earnings test, PGE has deferred 90% of the excess variance for 2021, or $30 million, which is expected to be collected from customers. See "Power Operations" within this Overview section of Item 2 for more information regarding the PCAM. Portland Harbor Environmental Remediation Account (PHERA) Mechanism-The U.S. Environmental Protection Agency( EPA) has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As of June 30, 2022, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision (ROD) issued in 2017, the EPAoutlined 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 billionto $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the range. The Company's liability related to the cost of remediating Portland Harbor could be material to PGE's financial position. The impact of such costs to the Company's results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company's recovery mechanism allows the Company to defer and recover estimated liabilities and incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, including, but not limited to, insurance recoveries, and customer prices, as necessary. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds, and annual expenditures in excess of $6 million, excluding contingent liabilities, are subject to an annual earnings test. PGE's results of operations may be impacted to the extent such expenditures were to be deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see " EPAInvestigation 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 46 -------------------------------------------------------------------------------- Table of Contents mechanism provided for collection from (or refund to) customers if weather-adjusted use per customer was less (or more) than that projected in the Company's most recent GRC. Collections under the decoupling mechanism were subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For estimated collections recorded in 2022, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2024. No limit existed for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic had resulted in larger estimated refunds under the decoupling mechanism, which had largely offset the revenue increases that had resulted from higher residential demand. In the 2022 GRC, parties reached an agreement that has eliminated PGE's decoupling mechanism upon the effective date of new customer prices pursuant to the case, which began May 9, 2022. Pursuant to the GRC Order, the OPUC adopted the agreement such that deferrals will cease in 2023, although amortization of previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices and deferral will continue on a prorated basis through the end of 2022. For the six months ended June 30, 2022the Company recorded an estimated total refund of $1 millionto residential and commercial customers that resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. The Company continues to see higher weather-adjusted use per customer from residential customers that are spending more time at home and lower use per customer from commercial customers that are adversely affected by the COVID-19 pandemic.
Deferral of Boardman Revenue Requirement-In
October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with the Company's Boardman coal-fired generating plant (Boardman) then included in customer prices as established in the Company's 2019 GRC. The application stated a deferral was required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. In October 2021, intervenors filed a motion with the OPUC requesting to consolidate the open Boardman deferral docket with PGE's open 2022 GRC docket. The Administrative Law Judge denied the consolidation, although did provide an opportunity to use the 2022 GRC proceeding to settle any issues with deferrals. PGE estimated the revenue requirement for Boardman to be $14 millionfor the period ended December 31, 2020, an additional $66 millionfor the year ended December 31, 2021, and $23 millionfor the six months ended June 30, 2022. Based on the application of an earnings test, PGE has not recorded a refund related to Boardman. In the 2022 GRC Order, the OPUC found that the deferral was warranted with amortization subject to an earnings test. On July 27, 2022, the Company filed an application, which, subject to OPUC approval, will show that the Company did not exceed the earnings test threshold for 2020 or 2021 and consequently, no refund would be required for those years. Customer prices resulting from the 2022 GRC Order no longer include any revenue requirement related to Boardman after new customer prices took effect on May 9, 2022. PGE does not expect to exceed its regulated return on equity under the earnings test for 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances or refunds, which could be material. Renewable Recovery Framework-As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the RAC, which allows PGE to recover prudently incurred costs through filings made by April 1steach year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent 47 -------------------------------------------------------------------------------- Table of Contents costs of energy storage projects associated with renewables in future RAC filings, under certain conditions. There have been no significant filings made under the RAC during 2022. Operating Activities In combination with electricity provided by its own generation portfolio, to meet its retail load requirements and balance its energy supply with customer demand, PGE purchases and sells electricity in the wholesale market. The Company also performs portfolio management and wholesale market sales services for third parties in the region. PGE also participates in the California Independent System Operator'sWestern Energy Imbalance Market, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United Statesand Canadato fuel its generation portfolio and sells excess gas back into the wholesale market. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company's revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations. Customers and Demand-The following tables present total energy deliveries and the average number of retail customers by customer type for the periods indicated: % Increase Three Months Ended June 30, Six Months Ended June 30, (Decrease) in % Increase (Decrease) Energy 2022 in Energy 2021 2022 Deliveries 2021 Deliveries Energy deliveries (MWhs in thousands): Retail: Residential 1,724 1,764 (2) % 3,940 4,003 (2) % Commercial 1,552 1,601 (3) % 3,186 3,165 1 % Industrial 998 916 9 % 1,972 1,813 9 % Subtotal 4,274 4,281 - % 9,098 8,981 1 % Direct access: Commercial 133 148 (10) % 264 298 (11) % Industrial 441 402 10 % 854 761 12 % Subtotal 574 550 4 % 1,118 1,059 6 % Total retail energy deliveries 4,848 4,831 - % 10,216 10,040 2 % Wholesale energy deliveries 1,425 1,259 13 % 2,932 2,504 17 % Total energy deliveries 6,273 6,090 3 % 13,148 12,544 5 % 48
Table of Contents Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Average number of retail customers: Residential 809,002 88 % 798,799 88 % 807,777 88 % 798,200 88 % Commercial 112,090 12 110,825 12 111,879 12 110,764 12 Industrial 193 - 190 - 192 - 191 - Direct access 553 - 584 - 552 - 593 - Total 921,838 100 % 910,398 100 % 920,400 100 % 909,748 100 % Total retail energy deliveries for the six months ended
June 30, 2022increased 2% compared with the six months ended June 30, 2021, driven by strong demand from the industrial customer class. The industrial class has experienced an increase in energy deliveries, due primarily to continued growth in the high-tech and digital services sectors. Residential usage continues to be elevated as remote and hybrid work schedules remain in place across the Company's service area, although total deliveries declined slightly, reflecting the impact of relative temperatures as 2022 saw heating and cooling degree-days closer to average than what was experienced during the first six months of 2021. The following table indicates the number of heating and cooling degree-days for the three and six months ended June 30, 2022and 2021, 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 Cooling Degree-days 2022 2021 Avg. 2022 2021 Avg. First Quarter 1,761 1,805 1,846 - - - April 454 290 365 - - 2 May 242 167 184 - 21 24 June 65 41 75 75 217 74 Second Quarter 761 498 624 75 238 100 Year-to-date 2,522 2,303 2,470 75 238 100 Increase/(decrease) from the 15-year average 2 % (7) % (25) % 138 % After adjusting for the effects of weather, total retail energy deliveries for the six months ended June 30, 2022increased 2.7% compared to the same period of 2021. The increase reflects 10% higher industrial delivery volumes, 1% more commercial delivery volumes, and residential deliveries that declined marginally when compared to the prior year. Residential weather-adjusted deliveries saw average usage per customer 1.5% lower during the first six months of 2022 compared with 2021, while the average number of residential customers was 1.2% greater during 2022 than 2021. The Company's cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from ESSs. This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE's total retail energy deliveries for the first six months of 2022. In early February 2020, PGE began offering service to customers under an OPUC created New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. With the adoption of the New Large Load Direct Access program, which is capped at 119 MWa, as much as 18% of the Company's energy deliveries could have been supplied by ESSs. Actual energy deliveries to Direct Access customers by ESSs represented 11% of PGE's total retail energy deliveries for the first six months of 2022 and 2021. 49 -------------------------------------------------------------------------------- Table of Contents 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, 2022and 2021: Actual energy provided Actual energy provided as a compared to projected percentage of total retail Plant availability (1) levels (2) load 2022 2021 2022 2021 2022 2021 Generation: Thermal: Natural gas 84 % 87 % 78 % 175 % 33 % 45 % Coal (3) 83 78 91 105 10 9 Wind (4) 74 85 80 112 9 13 Hydro 96 94 81 76 6 6 (1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2)Projected levels of energy are included as part of PGE's AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources. (3)Plant availability reflects Colstrip, which PGE does not operate. (4)Plant availability includes Wheatridge, which PGE does not operate. Energy received from PGE-owned and jointly-owned thermal plants during the six months ended June 30, 2022compared to 2021 decreased 19%. This decrease is primarily related to PGE's natural gas-fired plant which have been displaced by higher hydroelectric generation and purchases, and economic dispatch decisions in response to higher natural gas prices. Energy expected to be received from thermal resources is projected annually in the AUT based on forecast market prices, variable costs to run the plant, and the constraints of the plant. PGE's thermal generating plants require varying levels of annual maintenance, which is generally performed during the second quarter of the year. Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 35% during the six months ended June 30, 2022compared to 2021 primarily due to increased runoff resulting from favorable snowpack conditions. Energy purchased from mid- Columbiaand other regional hydroelectric projects increased 44% while energy generated by the Company-owned facilities decreased 3% in the six months ended June 30, 2022largely as a result of PGE's sale of 16.66% of its ownership interest in Pelton/Round Butte to the Confederated Tribes of the Warm Springs Reservationof Oregon(CTWS), effective January 1, 2022. PGE purchases 100% of the CTWS's share of the project output. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See "Purchased power and fuel" in the Results of Operations section in this Item 2, for further detail on regional hydro results. Energy received from PGE-owned wind resources and under contracts decreased 19% during the six months ended June 30, 2022compared to 2021 primarily due to unplanned plant outages during the period. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind 50 -------------------------------------------------------------------------------- Table of Contents 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 millionbelow to $30 millionabove 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, 2022and 2021, respectively: •For the six months ended June 30, 2022, actual NVPC was $32 millionbelow baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2022is currently estimated to be below the baseline, and outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE's preliminary regulatory ROE is estimated to be below 10.5% there is no estimated refund to customers expected under the PCAM for 2022. •For the six months ended June 30, 2021, actual NVPC was $6 millionbelow baseline NVPC. For the year ended December 31, 2021, actual NVPC was $62 millionabove baseline NVPC, which was outside the established deadband range. Pursuant to the PCAM, as PGE's preliminary regulatory ROE was below 8.5% pursuant to the related earnings test PGE deferred $30 million, which represents 90% of the excess variance expected to be collected from customers. A final determination regarding the 2021 PCAM results will be made by the OPUC through a public filing and review in 2022. The OPUC has significant discretion in making the final determination of recovery. The OPUC's conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE's deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. 51
-------------------------------------------------------------------------------- Table of Contents Results of Operations
The following tables provide financial and operational information to be considered in conjunction with management's discussion and analysis of results of operations.
The results of operations are as follows for the periods presented (dollars in millions): Three Months Ended June Six Months Ended 30, % Increase June 30, 2022 (Decrease) 2021 2022 % Increase (Decrease) 2021 Total revenues
$ 591$ 537 10 % $ 1,217 $ 1,1466 % Operating expenses: Purchased power and fuel 168 185 (9) % 370 354 5 % Generation, transmission and distribution 85 76 12 % 175 156 12 % Administrative and other 84 79 6 % 173 165 5 % Depreciation and amortization 103 101 2 % 202 204 (1) % Taxes other than income taxes 39 35 11 % 79 73 8 % Total operating expenses 479 476 1 % 999 952 5 % Income from operations 112 61 84 % 218 194 12 % Interest expense, net* 38 33 15 % 76 67 13 % Other income: Allowance for equity funds used during construction 3 5 (40) % 6 9 (33) % Miscellaneous income, net - 3 (100) % - 5 (100) % Other income, net 3 8 (63) % 6 14 (57) % Income before income tax expense 77 36 114 % 148 141 5 % Income tax expense 13 4 225 % 24 13 85 % Net income 64 32 100 % 124 128 (3) % Other comprehensive income 1 - - % 1 - - % Net income and Comprehensive income $ 65$ 32 103 % $ 125 $ 128(2) %
* Includes an allowance for borrowed funds used during construction of
Net income for the three months ended
June 30, 2022was double that of the three months ended June 30, 2021as total revenues increased while Purchased power and fuel expenses declined. Revenues increased as a result of several factors, including an increase in customer prices to cover anticipated higher net variable power costs as authorized by the OPUC in the AUT. The Company was able to optimize forward contracts for power and natural gas to lower its Purchased power and fuel expense compared to the same period of 2021, thus improving income from operations. Wholesale revenues also increased substantially while Other operating revenues reflected gains from the sale of excess natural gas back into the market. Total operating expenses were comparable to the prior year quarter as the savings in Purchased power and fuel expense mostly offset modest increases in the other line items. Other income declined primarily due to changes in performance of the Non-qualified benefit plan trust assets. Income taxes increased due primarily to higher Income before income tax expense. 52
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Net income for the six months ended
June 30, 2022was comparable to the same period of 2021. Wholesale revenues were the largest contributor to higher revenues in 2022 as both volumes and prices have increased. Increases in Retail revenues were led by the increase in customer prices to cover anticipated higher net variable power costs, as authorized by the OPUC in the AUT, which were anticipated to be offset by higher power costs. Retail energy deliveries increased 2%, primarily driven by continued growth in industrial demand, including high-tech manufacturing. The impact of higher natural gas and electricity prices coupled with increased customer demand also drove Purchased power and fuel expense up. Retail revenues were impacted by a slightly lower average price mix in 2022 as a result of the increased demand in the industrial sector. Increases in Operating expenses reflect the result pursuant to the earnings tests outlined in Order 22-129, expenses related to service restoration costs, and continued vegetation management activities. Higher relative Income tax expense in 2022 reflects higher Income before income tax expense in the second quarter of 2022 as well as the favorable impact of a local tax flow-through adjustment that occurred in the first quarter of 2021. Total revenues consist of the following for the periods presented (dollars in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Retail: Residential $ 25042 % $ 24946 % $ 55846 % $ 55949 % Commercial 168 28 170 32 346 29 332 29 Industrial 73 12 62 11 142 12 122 11 Direct Access* 9 2 13 2 17 1 24 2 Subtotal 500 84 494 91 1,063 88 1,037 91 Alternative revenue programs, net of amortization 3 1 (8) (1) 4 - (11) (1) Other accrued revenues, net - - (2) - - - 11 1 Total retail revenues 503 85 484 90 1,067 88 1,037 91 Wholesale revenues 65 11 41 8 121 10 74 6 Other operating revenues 23 4 12 2 29 2 35 3 Total revenues $ 591100 % $ 537100 % $ 1,217100 % $ 1,146100 % * Commercial revenues from Direct Access customers for the three and six months ended June 30, 2022were $3 millionand $6 million, respectively. For the comparable three- and six-month periods of 2021, revenues were $5 millionand $9 million, respectively. Industrial revenues from Direct Access customers for the three and six months ended June 30, 2022were $6 millionand $11 million, respectively. For the comparable three- and six-month periods of 2021, revenues were $7 millionand $15 million, respectively. 53 -------------------------------------------------------------------------------- Table of Contents Total retail revenues-The following items contributed to the increase in Total retail revenues for the three and six months ended June 30, 2022compared to the same periods in 2021 as follows (in millions): Three Months Ended Six Months Ended June 30, 2021 $ 484 $ 1,037
Increase as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)
Increase from higher retail energy deliveries driven by customer load growth
Increase attributed to alternative revenue programs related to the decoupling mechanism due primarily to increased residential use per customer in 2021 and prorated elimination of the mechanism in 2022
Decrease resulting from the combination of various supplemental tariffs and adjustments
(3) (2) Recovery in Revenues of storm related expenses 4 (7)
Decrease as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19 economic recovery and increased industrial demand
(4) (15) June 30, 2022 $ 503 $ 1,067 Change in Total retail revenues $ 19 $ 30 Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company's efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. For the three months ended
June 30, 2022, Wholesale revenues increased $24 millionor 59% from the three months ended June 30, 2021as an $18 millionincrease from 40% higher average wholesale sales price was combined with a $6 millionincrease due to a 13% increase in sales volumes. Although prices were high in the three months ended June 30, 2021due to weaker than average regional hydro production in 2021, reduced regional capacity, and the demand impact resulting from the extreme heat event experienced in June 2021, prices have continued to increase during 2022 due to strong demand, the impact on natural gas prices due to global energy issues, and ongoing capacity limitations in the region. Wholesale revenues for the six months ended June 30, 2022increased $47 millionfrom the six months ended June 30, 2021, as the average wholesale sales price increased 39% driving $34 millionof the increase. The higher sales prices have resulted from several factors including the overall economic recovery and macroeconomic factors impacting the energy commodity markets, but were driven largely by higher natural gas prices. In addition, sales volumes were up 17%, which contributed another $13 million. Other operating revenues increased $9 millionfor the three months ended June 30, 2022compared with the same period in 2021 as market conditions allowed the Company to sell excess natural gas at a gain. In the six months ended June 30, 2022, Other operating revenues decreased $6 millioncompared to the same period of 2021. In the first quarter of 2021, market conditions allowed the Company to sell excess natural gas at a gain of $10 million, whereas in 2022 such excess gas was sold at a $6 millionloss. 54 -------------------------------------------------------------------------------- Table of Contents 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, 2022compared to the same period in 2021 (dollars in millions, except for average variable power cost per Megawatt hour (MWh)): Three Months Ended Six Months Ended June 30, 2021 $ 185 $ 354 Decrease related to average variable power cost per MWh (61) (57) Increase related to total system load 44 73 June 30, 2022 168 370 Change in Purchased power and fuel $ (17) $ 16 Average variable power cost per MWh: June 30, 2021 $ 32.08 $ 29.51 June 30, 2022 $ 28.40 $ 29.43 Total system load (MWhs in thousands): June 30, 2021 5,754 11,991 June 30, 2022 5,946 12,594 For the three months ended June 30, 2022, the $61 milliondecrease related to the change in average variable power cost per MWh was driven by a 22% decrease in the average cost of purchased power and a 51% decrease on the average cost for the Company's own generation. Total energy received from hydroelectric generation sources, both PGE-owned and purchased, increased significantly due to above average runoff conditions, which reduced power costs and economically displaced power from the Company's higher cost natural gas-fired plant sources. The $44 millionincrease related to total system load was primarily due to a 42% increase in deliveries of energy obtained from purchased power based on economic dispatch decisions. This was offset by a 29% decrease in the Company's own generation. For the six months ended June 30, 2022, the $57 milliondecrease related to the change in average variable power cost per MWh was driven by a 10% decrease in the average cost of purchased power and a 25% decrease on the average cost for the Company's own generation. The $73 millionincrease related to total system load was primarily due to a 38% increase in deliveries of energy obtained from purchased power resulting from the economic displacement of gas facilities in 2022. This was offset by an 18% decrease in the Company's own generation. 55 -------------------------------------------------------------------------------- Table of Contents PGE's sources of energy, total system load, and retail load requirement for the periods presented are as follows: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Sources of energy (MWhs in thousands): Generation: Thermal: Natural gas 1,086 18 % 1,906 33 % 3,235 26 % 4,289 36 % Coal 356 6 313 5 966 8 895 7 Total thermal 1,442 24 2,219 38 4,201 34 5,184 43 Hydro 293 5 264 5 566 4 581 5 Wind 516 9 665 12 908 7 1,197 10 Total generation 2,251 38 3,148 55 5,675 45 6,962 58 Purchased power: Hydro 2,002 33 1,343 23 3,564 27 2,472 21 Wind 250 4 244 4 445 4 482 4 Solar 216 4 175 3 329 3 267 2 Natural Gas - - - - 2 - 4 - Waste, Wood and Landfill Gas 42 1 44 1 79 1 83 1 Source not specified 1,185 20 800 14 2,500 20 1,721 14 Total purchased power 3,695 62 2,606 45 6,919 55 5,029 42 Total system load 5,946 100 % 5,754 100 % 12,594 100 % 11,991 100 % Less: wholesale sales (1,425) (1,259) (2,932) (2,504) Retail load requirement 4,521 4,495 9,662 9,487 Purchased power in the table above includes power received from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) as follows: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Sources of energy (MWhs in thousands): PURPA purchased power: Hydro 8 5 14 10 Wind 8 9 13 15 Solar 178 164 282 252 Waste, Wood and Landfill Gas 24 29 45 47 Total 218 207 354 324
The following table presents the forecast April-to-
Runoff as a Percent of Normal*
Location 2022 Forecast 2021 Actual Columbia River at The Dalles, Oregon 110 % 82 % Mid-Columbia River at Grand Coulee, Washington 114 89 Clackamas River at Estacada, Oregon 141 70 Deschutes River at Moody, Oregon 94 84
* Volumetric water supply forecasts and historical averages for the
Table of Contents
Actual NVPC for the three and six months ended
Three Months Ended Six Months
June 30, 2021 $ 144 $
Purchased power and fuel expense (17)
16 Wholesale revenues (24) (47) June 30, 2022 $ 103 $ 249 Change in NVPC $ (41) $ (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, 2022and 2021, actual NVPC was $17 millionbelow and $19 millionabove baseline NVPC, respectively. For the six months ended June 30, 2022and 2021, actual NVPC was $32 millionbelow and $6 millionabove baseline NVPC, respectively. Based on forecast data, NVPC for the year ending December 31, 2022is currently estimated to be below the baseline, and outside the deadband. Pursuant to the PCAM's earnings test, because PGE's preliminary regulatory ROE is expected to be below 10.5%, there is no estimated refund to customers expected under the PCAM for 2022. Generation, transmission and distribution increased as follows for the three and six months ended June 30, 2022compared to the same periods in 2021 (in millions): Three Months Ended Six Months Ended June 30, 2021 $ 76 $ 156 Release of previously deferred amounts pursuant to earnings - 16
test created in OPUC 2022 GRC Order Higher service restoration and storm response costs, other than
7 6 Higher employee compensation and benefits expenses 3 6
(Lower)/higher distribution vegetation management, inspection, and maintenance expenses
(1) 3 February 2021 wind and ice storm restoration expenses - (13) Miscellaneous expenses - 1 June 30, 2022 $ 85 $ 175 Change in Generation, transmission and distribution $ 9 $ 19
PGE experienced higher Generation, transmission and distribution expenses largely from vegetation management activities coupled with a strong labor market and rising cost of materials and supplies.
57 -------------------------------------------------------------------------------- Table of Contents Administrative and other increased for the three and six months ended
June 30, 2022compared to the same periods in 2021 as follows (in millions): Three Months Ended Six Months Ended June 30, 2021 $ 79 $ 165 Regulatory program amortization 2 3 Higher professional service expenses 2 2 (Lower)/higher employee compensation and benefits expenses (2) 1 Lower bad debt expense (2) (3) Miscellaneous expenses 5 5 June 30, 2022 $ 84 $ 173 Change in Administrative and other $ 5 $ 8 Higher Administrative and other expenses reflect increases for employee wage and benefit expenses and outside services, including labor, driven by a strong labor market, as well as the cost of materials. Depreciation and amortization expense increased $2 millionfor three months ended June 30, 2022compared to the same period in 2021. The increase for the three months ended June 30, 2022was driven by accelerated depreciation of the Colstripfacility as approved by the OPUC's 2022 GRC Order and commenced in May 2022, as well as higher plant balances from capital additions, partially offset by regulatory amortization and deferral activity. Depreciation and amortization expense decreased $2 millionfor the six months ended June 30, 2022, compared to the same period in 2021. The decrease was driven by regulatory amortizations and deferral activity, partially offset by accelerated depreciation of the Colstripfacility, as well as higher plant balances from capital additions. Taxes other than income taxes expense increased $4 millionand $6 millionin the three and six months ended June 30, 2022, respectively, compared to the same periods in 2021. The increases for both the three and six months ended were driven by higher franchise, payroll, and property tax expenses. Interest expense, net increased $5 millionand $9 millionin the three and six months ended June 30, 2022compared to the same periods in 2021 due to higher lease-related interest expenses and higher long-term debt balances. Other income, net decreased $5 millionand $8 millionfor the three and six months ended June 30, 2022compared to the same periods in 2021. The decreases were driven by unfavorable market changes on the non-qualified benefit trust and lower AFUDC equity income on lower construction work-in-progress balances. Income tax expense increased $9 millionand $11 millionfor three and six months ended June 30, 2022, compared to the same period in 2021. The increase for the three months ended June 30, 2022was driven by an increase in pre-tax income. The increase for the six months ended June 30, 2022was driven by a cumulative catch-up adjustment recorded in the first quarter of 2021 to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax. See Note 10, Income Taxes, in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements," for more information.
Critical Accounting Policies and Estimates
There have been no material changes to the Company's critical accounting policies and estimates as previously disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended
December 31, 2021, filed with the SECon February 17, 2022. 58
-------------------------------------------------------------------------------- Table of Contents LIQUIDITY AND CAPITAL RESOURCES
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, 2022 2021 Cash and cash equivalents, beginning of period $ 52
$ 257Net cash provided by (used in): Operating activities 451 276 Investing activities (334) (337) Financing activities (78) (179) Increase (decrease) in cash and cash equivalents 39 (240) Cash and cash equivalents, end of period $ 91
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, 2022compared with the six months ended June 30, 2021(in millions): Increase/ (Decrease) Decrease in Net income $ (4)Increase in Margin deposits received from wholesale counterparties due to 132
natural gas commodity prices Increase related to Margin deposits paid to wholesale counterparties due to natural gas commodity prices
Increase related to the Deferral of incremental storm costs in 2021
Increase as a result of changes in Accounts receivable and Unbilled revenue
46 Decrease in Accounts payable primarily due to the timing of payments to vendors (68) Increase related to the 2020
Labor Daywildfire earnings test reserve non-cash adjustment to Net income 15 Change in Decoupling mechanism deferrals, net of amortization (15) Other miscellaneous changes (18) Net change in cash flow from operations
PGE estimates that non-cash charges for depreciation and amortization in 2022 will range from
$410 millionto $430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $600 millionto $650 million. 59
Table of Contents
Cash Flows from Investing Activities-Net cash used in investing activities for the six months ended
June 30, 2022decreased $3 millionwhen compared with the six months ended June 30, 2021. 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 $20 million, offset by a $12 milliondecrease related to proceeds from the sale of property and a $12 milliondecrease in other costs of removal related to the 2021 winter storm restoration. Excluding AFUDC, the Company plans to make capital expenditures of $755 millionin 2022, which it expects to fund with cash to be generated from operations during 2022, as discussed above, and the issuance of short- and long-term debt securities. 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, 2022, net cash used in financing activities was primarily the result of payment of $77 millionof dividends, proceeds from failed sale-leaseback transactions of $25 million, and repurchase of common stock of $18 million.
The following table presents PGE's estimated capital expenditures and contractual maturities of long-term debt for 2022 through 2026, excluding AFUDC (in millions).
2022 2023 2024 2025 2026 Ongoing capital expenditures(1)
$ 735 $ 635 $ 650 $ 650 $ 650Integrated Operations Center 20 15 - - - Total capital expenditures(2) $ 755 $ 650 $ 650 $ 650 $ 650Long-term debt maturities $ - $ - $ - $ - $ - (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, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company's anticipated capital and operating requirements for the foreseeable future. For 2022, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from
$600 millionto $650 million, issuances of long-term debt securities of up to $220 million, and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments. 60 -------------------------------------------------------------------------------- Table of Contents Short-term Debt. Pursuant to an order issued by the FERCon January 20, 2022, PGE has authorization to issue short-term debt up to a total of $900 millionthrough February 6, 2024. The following table shows available liquidity as of June 30, 2022(in millions): As of June 30, 2022Capacity Outstanding
Revolving credit facility (1)
$ 650$ - $ 650Letters of credit (2) 220 91 129 Total credit $ 870$ 91 $ 779Cash and cash equivalents 91 Total liquidity $ 870(1)Scheduled to expire September 2026. (2)PGE has three letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year. In September 2021, PGE amended and restated its existing revolving credit facility. As of June 30, 2022, PGE had a $650 millionrevolving credit facility scheduled to expire in September 2026. 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. 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, 2022, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $650 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
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 45.5% and 45.2% as of
June 30, 2022and December 31, 2021respectively. 61 -------------------------------------------------------------------------------- Table of Contents Credit Ratings and Debt Covenants PGE's secured and unsecured debt is rated investment grade by Moody's InvestorsService (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 Stable Stable 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, 2022, PGE had posted $59 millionof collateral with these counterparties, consisting of $29 millionin cash and $30 millionin 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, 2022, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $90 million, and decreases to $22 millionby December 31, 2022. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $170 millionand decreases to $103 millionby December 31, 2022and to $92 millionby December 31, 2023. 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 First Mortgage Bonds (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, 2022, under the most restrictive issuance test in the Indenture, the Company could have issued up to $618 millionof 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, 2022, the Company's debt-to-total capital ratio, as calculated under the credit agreement, was 55.6%.
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