PORTLAND GENERAL ELECTRIC CO /OR/ - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS.
- Feb 19, 2021 8:28 am GMTFeb 19, 2021 3:23 pm GMT
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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 FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition; •economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts; •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 ESSs or community choice aggregators; •the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 19, Contingencies, in the Notes to Consolidated Financial Statements in Item 8.- "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K; •unseasonable or extreme weather and other natural phenomena, which could affect customers' demand for power and PGE's ability and cost to procure adequate power and fuel supplies to serve its customers, and could increase the Company's costs to maintain its generating facilities and transmission and distribution systems; •operational factors affecting PGE's power generating facilities, including forced outages, 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; 30
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•complications arising from PGE's jointly-owned generating facilities, 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; •failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company's inability to recover project costs; •volatility in wholesale power and natural gas prices that could require PGE to post additional collateral or issue additional letters of credit pursuant to power and natural gas purchase agreements; •changes in the availability and price of wholesale power and fuels, including natural gas and coal, and the impact of such changes on the Company's power costs; •capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE's credit ratings, any of which could have an impact on the Company's cost of capital and its ability to access the capital markets to support requirements for working capital, construction of capital projects, and the repayments of maturing debt; •future laws, regulations, and proceedings that could increase the Company's costs of operating its thermal generating plants, or affect the operations of such plants by imposing requirements for additional emissions controls or significant emissions fees or taxes, particularly with respect to coal-fired generating facilities, in order to mitigate carbon dioxide, mercury and other gas emissions; •changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife; •the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company's costs, or adversely affect its operations; •changes in residential, commercial, or industrial customer growth, or demographic patterns, in PGE's service territory; •the effectiveness of PGE's risk management policies and procedures; •cybersecurity attacks, data security breaches, or other malicious acts that cause damage to the Company's generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information; •employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and the ability to recruit and retain appropriate talent; •new federal, state, and local laws that could have adverse effects on operating results; •political and economic conditions; •natural disasters and other risks, such as pandemic, earthquake, flood, drought, lightning, wind, and fire; •the impact of widespread health developments, including the global coronavirus (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 •the impact of the recommendations on the Company and its operations based on the review conducted by the Special Committee relating to energy trading losses, the time and expense incurred in implementing the recommendations of the Special Committee, and any reputational damage to the Company relating to the matters underlying the Special Committee's review. 31
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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. MD&A should be read in conjunction with the Company's consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC. PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale purchase and sale of electricity and natural gas in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory. In addition, the Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers.
PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company expects to manage commodity price volatility within net variable power costs by engaging in energy trading activities. The Company does not intend to engage in trading activities for non-retail purposes. PGE personnel entered into a number of energy trades during 2020, with increasing volume accumulating late in the second quarter and into the third quarter, resulting in significant exposure to the Company. In August 2020, a portion of energy trading positions in PGE's energy portfolio experienced significant losses as wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. During this time period, the CAISO declared a Stage 3 Electrical Emergency and ordered the first rolling blackouts in the state of California since 2001. As a result of the convergence of these conditions, the Company's energy portfolio experienced realized losses of $127 million on these positions in 2020. PGE determined the energy trading positions that led to the losses were outside the Company's acceptable risk tolerances, and the Company will not pursue regulatory recovery of the associated losses. PGE will also exclude the impacts of the realized losses from its regulatory earnings tests. The increase in net variable power costs due to this trading activity has been recognized in PGE's results of operations. PGE no longer has net market exposure from the energy trading positions that led to these losses. PGE and its external consultants have performed a full operational review of the Company's energy supply risk management policies, procedures and personnel. In addition, the PGE Board of Directors formed a Special Committee comprising five independent Board members to review the energy trading that led to the losses and the Company's procedures and controls related to the trading, and to make recommendations to the Board for appropriate action. The Special Committee retained independent legal advisors. On December 18, 2020, PGE announced that the Special Committee concluded its independent review of the energy trading activity that led to the losses incurred in the third quarter of 2020. The Special Committee concluded that the trades were ill-conceived and revealed opportunities for improving the Company's energy trading policies and practices. Additionally, the Board of Directors concluded that the actions the Company began taking in August to enhance oversight of energy trading and associated risk management reporting, policies, and practices were consistent with the Special Committee's recommendations and will be monitored by the Board of Directors through enhanced reporting. These actions are expected to strengthen the Company and include: 32
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•Added expertise: PGE brought in additional experienced risk management personnel and replaced the Power Operations general manager with a new leader; •Strengthened trading policies: Power Operations personnel are operating under revised policies designed to prevent positions of the type that led to the losses. The improved policies place controls on the ability of personnel to enter into wholesale energy transactions to the extent that PGE does not have physical or financial delivery capability; •Enhanced risk reporting: Energy trading activity reporting has been improved to ensure greater visibility into portfolio risk; •Changed reporting structures: Energy Trading Risk Management now reports through a Risk and Compliance team that reports to the Chief Executive Officer. Effective January 1, 2021, Power Operations reports to the Vice President of Strategy, Regulation and Energy Supply; and •Changed personnel: The individuals who previously were placed on leave are no longer with the Company.
For further information regarding legal proceedings associated with this matter, see "Shareholder Lawsuits" in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data."
The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions. In the state of Oregon, the Governor issued an executive order on March 23, 2020 directing Oregon residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact was difficult or impossible to avoid. This order was rescinded May 14, 2020 in a new executive order announcing a phased approach for reopening Oregon's economy. The subsequent phased reopening approach has not allowed all businesses to reopen, or has allowed reopening only at reduced capacity to meet requirements for social distancing. The continued loosening of restrictions is contingent upon the successful reduction of cases. Retail loads-The slowdown in certain sectors of the economy due to COVID-19 and the initial stay-at-home order and subsequent phased reopening plans has resulted in changes in retail load patterns. See "Customers and Demand" and "Decoupling" in this Overview section and "Revenues" of the Results of Operations section for more information related to COVID-19 impacts on retail loads and Revenues, net. Bad debt expense-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. PGE's bad debt expense was $15 million for the full-year 2020, compared to an original $6 million forecast, subject to deferral. See "Administrative and other" of the Results of Operations section for more information related to COVID-19 impacts on bad debt expense, and see "Legislative and regulatory developments" within this Overview section for more information regarding regulatory deferrals of incremental costs associated with the COVID-19 pandemic. Financial condition and liquidity-Global capital markets have experienced significant volatility in response to COVID-19 and PGE continues to assess the impact of this volatility on its liquidity position and capital investment plans. The Company believes the combination of its revolver capacity, proceeds of a $150 million, 364-day term loan, issued in April 2020, and proceeds from $200 million and $230 million FMB issuances, in April and November 2020, respectively, will continue to provide adequate liquidity for the Company's operational needs. The Company continues to evaluate its five-year capital plan. A detailed discussion of capital market and capital investment responses is included in the Liquidity and Capital Resources section of this Item 7.
The COVID-19 pandemic did not have a material impact on PGE's financial condition and cash flows in 2020 and the Company continues to have sufficient liquidity to meet the Company's anticipated capital and operating
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requirements going forward. It is reasonably possible, however, that disruption and volatility in the global capital markets may materially increase the cost of capital. Supply chain-The global nature of the COVID-19 pandemic has resulted in supply chain disruptions and in some instances construction interruptions, although PGE has not experienced significant supply chain disruptions or construction interruptions to date. The Company's business continuity plans have included an assessment of critical operational supply chain linkages and an assessment of potential interruptions to its capital project execution. The Company will continue to monitor supply chain issues, including possible force majeure notices, for any material impacts to its operations. Business continuity plans-In February 2020, as more information about the potential impacts of COVID-19 became available, the Company activated its business continuity plans. These plans are designed to ensure the safety of the public and employees while the Company continues to provide critical service to its customers. In addition to directing employees to work from home when appropriate, the Company has implemented safeguards for employees who play critical roles to ensure operational reliability and established protocols for employees who interact directly with the public. The Company has enacted extra physical security and cybersecurity measures to safeguard systems to serve operational needs, including those of its remote workforce, and to ensure uninterrupted service to customers. The Company will continue to evolve its business continuity plans to follow guidance from the Centers for Disease Control and the Oregon Health Authority. Although PGE has plans in place to address workforce availability, including sequestration of key employees if necessary, the Company has not experienced workforce availability issues to date. Implementation of PGE's business continuity plans have not had a material impact on PGE's results of operation. Legislative and regulatory developments-The Company has analyzed available relief for the economic effects of COVID-19 under the following: •FERC Waiver-On June 30, 2020 the FERC issued a waiver that provides that, for the 12-month period starting March 2020, jurisdictional utilities may apply an alternative allowance for funds used during construction (AFDC) calculation formula that excludes the actual outstanding short-term debt balance and replaces it with the simple average of the actual 2019 short-term debt balance. The purpose of the waiver is to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction. PGE adopted the waiver in the second quarter of 2020 and retrospectively applied its provisions as of March 2020, resulting in a $1 million increase to AFDC. The Company continues to monitor for potential extensions of the waiver beyond the original 12-month period. •Coronavirus Aid, Relief, and Economic Security (CARES) Act-On March 27, 2020, the U.S. Government enacted the CARES Act, which provides economic relief and stimulus to support the national economy during the COVID-19 pandemic and includes support for individuals, large corporations, small business, and health care entities, among other affected groups. The Company has not experienced direct material benefits from the CARES Act. •COVID-19 Deferral-PGE filed an application for deferral of certain incremental costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. 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, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers. 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. On September 24, 2020, the Commission adopted OPUC Staff's motion to execute stipulations incorporating the terms of the Term Sheet. PGE's deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of December 31, 2020, PGE has deferred $8 million related to bad debt expense, and $2 million for other incremental costs associated with COVID-19 under the Term Sheet. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable. 34
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Amortization of any deferred costs will remain subject to OPUC review prior to amortization and inclusion in customer prices. Although PGE expects its 2020 regulated ROE, after adjusting for certain energy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is 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 and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE's 2020 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings.
PGE is committed to continuing to achieve steady growth and returns as the Company transforms to meet the challenges of climate change and an ever-evolving energy grid. Customers, policy makers, and other stakeholders expect PGE to reduce GHG emissions, keep the power grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company's strategy strives to balance these interests. PGE plans to: •Reduce GHG emissions associated with the power served to customers by 80% by 2030 (2010 baseline year), and setting an aspirational goal for zero GHG emissions associated with the power served to customers by 2040; •Electrify sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and •Perform as a business, driving improvements to work efficiency, safety of our coworkers, and reliability of our systems and equipment all while adhering to the Company's earnings per diluted share growth guidance of 4-6% on average. Decarbonize the power supply-PGE partners with customers and local and state governments to advance a clean energy future. PGE continues to leverage these partnerships to pursue emission reductions using a diverse portfolio of clean and renewable energy resources, and promote economy-wide emission reductions through electrification and smart energy use to help the state meet its GHG emission reduction goals. In addition to state greenhouse gas reduction goals, PGE announced in 2020 a new company wide goal of achieving net zero GHG emissions by 2040. PGE also announced a new goal to meet customer expectations for clean energy, pledging to reduce GHG emissions associated with the power served to customers by 80% by 2030 (2010 baseline year).
To reach these goals, PGE will focus on the following areas:
Customer Choice Programs-PGE's customers continue to express a commitment to purchasing clean energy, as over 230,000 customers voluntarily participate in PGE's Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon's most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100 percent clean and renewable electricity by 2035 and 100 percent economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE's service area continue to consider similar goals. In response, the Company has implemented a new customer product option, the Green Future Impact program, which allows for 100 MW of PGE-provided power purchase agreements for renewable resources and up to 200 MW of customer-provided renewable resources. Approved by the OPUC in the first quarter 2019, the program will provide business customers access to bundled renewable attributes from those resources. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system. Pursuant to the OPUC order approving the Green Future Impact tariff, program subscribers remain cost of service customers, and pay both the cost of service tariff price and the price under the renewable energy option tariff. This structure is intended to avoid stranded costs and cost shifting. 35
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Carbon Legislation and Administrative Actions-In 2016, SB 1547 set a benchmark for how much electricity must come from renewable sources like wind and solar and requires the elimination of coal from Oregon utility customers' energy supply no later than 2030 (subject to an exception that allows extension of this date until 2035 for PGE's output from Colstrip). Other provisions of the law include: •An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040; •A limitation on the life of Renewable Energy Credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and •An allowance for energy storage costs related to renewable energy in the Company's RAC filings. In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE's investment in the Colstrip facility from 2042 to 2030. In January 2020, the owners of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has no direct ownership interest in Units 1 and 2, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2. Although PGE is currently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have sought approval to recover their costs sooner in their respective jurisdictions. In its most recent depreciation study filed with the OPUC in January 2021, PGE proposed to accelerate depreciation on Colstrip generation assets through 2027. The Company continues to evaluate its ongoing investment in Colstrip, including the possibility of earlier closure of these facilities. Any reduction in generation from Colstrip has the potential to provide capacity on the Colstrip transmission facilities, which stretches from eastern Montana to near the western end of the state to serve markets in the Pacific Northwest and beyond. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development in the state of Montana could benefit from any excess transmission capacity that may become available.
As previously planned, in October 2020, PGE ceased coal-fired operation at Boardman and has begun decommissioning activities.
During the 2019 Oregon legislative session, House Bill (HB) 2020 was introduced, which would have authorized a comprehensive cap and trade package in Oregon and would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted in 2019, an amended version was reintroduced in the 35-day legislative session, which began in February 2020. This new proposal, SB 1530, was also a cap and trade package that included changes made to address concerns raised by various parties. Prior to the legislative session, the OPUC stated that it would continue to collaborate with the legislature and stakeholders to make progress on climate change, noting that their authority was limited to that of an economic regulator. The short 2020 legislative session adjourned without action on SB 1530 and, as a result, in March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions. Many of the direct agency actions are on an aggressive timeline with due dates in 2020 and 2021. As the Governor is limited by current statutory authority, the executive order does not include a market-based mechanism as envisioned by the cap and trade legislation introduced in the 2019 and 2020 legislative sessions. Among other things, the executive order: •Modified the statewide GHG emissions reduction goals to at least 45% below 1990 emission levels by 2035 and at least 80% below 1990 emission levels by 2050; 36
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•Directed state agencies to integrate climate change and the State's GHG emissions reduction goals into their planning, budgets, investments, and decisions to the extent allowed by law; •Directed the OPUC to- •determine whether utility portfolios and customer programs reduce risks and costs to utility customers by making rapid progress towards reducing GHG emissions consistent with Oregon's reduction goals; •encourage electric companies to support transportation electrification infrastructure that supports GHG emission reductions and zero emission vehicle goals; and •prioritize proceedings and activities that advance decarbonization in the utility sector and exercise its broad statutory authority to reduce GHG emissions, mitigate energy burden on utility customers, and ensure reliability and resource adequacy; •Directed the Oregon Department of Environmental Quality to adopt a program to cap and reduce GHG emissions from large stationary sources, transportation fuels, and other liquid or gaseous fuels including natural gas; and •More than doubled the reduction goals of the state's Clean Fuels Program and extended the program, from the previous rule that required a 10 percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035. The Resource Planning Process-PGE's planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. This process includes consideration of customer expectations and legislative mandates to move away from fossil fuel generation and toward renewable sources of energy. In May 2018, the Company issued a request for proposals seeking to procure approximately 100 MWa of qualifying renewable resources. The prevailing bid was Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage. PGE now owns 100 MW of the wind resource, which was placed into service in the fourth quarter of 2020 at a cost of $149 million and qualified for PTCs at the 100 percent level. Subsidiaries of NextEra Energy Resources, LLC own the balance of the 300 MW wind resource, along with the solar and battery components, and will sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to increase its ownership to include the entire facility in 2032. Construction of the solar and battery components is planned for 2021 and is also expected to qualify for federal investment tax credits. PGE did not experience any supply chain disruptions due to the COVID-19 pandemic related to the construction of Wheatridge, and the solar and battery portions of the project are proceeding as planned. PGE continues to work closely with the contractor to actively monitor for supply chain issues. See "COVID-19 Impacts" within this Overview section for further information on COVID-19. On May 6, 2020, the OPUC issued an order that acknowledged the Company's 2019 IRP and the following Action Plan for PGE to undertake over the next four years to acquire the resources identified: •Customer actions- •Seek to acquire all cost-effective energy efficiency; and •Seek to acquire all cost-effective and reasonable distributed flexibility. •Renewable actions-Conduct a Renewables Request for Proposals (RFP) seeking up to approximately 150 MWa of new RPS-eligible resources that contribute to meeting PGE's capacity needs by the end of 2024, with the following conditions, among others: •Resources must qualify for PTC or the federal Investment Tax Credit; 37
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•Resources must pass the cost-containment screen; and •The value of RECs generated prior to 2030 must be returned to customers. •Capacity actions-Pursue dispatchable capacity through the following concurrent processes: •Pursue cost-competitive, bilateral contract agreements for existing capacity in the region; and •Conduct an RFP for non-emitting dispatchable resources that contribute to meeting PGE's capacity needs. The order also requires that PGE consider resources in the Renewable and Capacity RFPs in a co-optimized manner. PGE had requested authorization to pursue up to approximately 700 MW of capacity contribution by 2025 from a combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage. As PGE implements the Action Plan, the Company will continue to evaluate present and ongoing resource needs and timing of any related RFP in light of the economic disruption related to COVID-19. PGE expects to issue an RFP for both renewable energy and capacity resources. PGE and Douglas County Public Utility District entered an agreement during 2020 to supply the Company additional capacity from facilities including the Wells Hydroelectric Project, located on the Columbia River in central Washington. The agreement also provides Douglas County PUD with PGE load management and wholesale market sales services. With a start date of January 1, 2021, the five-year agreement is expected to contribute between 100 and 160 MWs toward a capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company's stated goal of providing customers with a clean energy future. PGE filed an IRP Update with the OPUC in January 2021 seeking acknowledgement so that it may incorporate the updated resource cost and value information in PURPA QF avoided cost pricing. No changes were proposed to the 2019 IRP Action Plan in the IRP Update. However, based on the updated capacity need forecast reflecting the addition of the agreement with the Douglas County PUD and more sophisticated modeling, the updated capacity need in 2025 is 511 MW. Renewable Recovery Framework-As previously authorized by the OPUC, the RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. Although no significant filings were made under the RAC during 2020, the Company did submit a RAC filing for Wheatridge in the fourth quarter of 2019. On September 29, 2020, the OPUC issued an order in response to PGE's RAC filing that stated PGE's decision to proceed with Wheatridge was prudent and authorized cost recovery of, and return on, the facility in customer prices once service to PGE's customers began, in the fourth quarter 2020. Electrify other sectors of the economy-PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include: •The use of electricity in more applications such as electric vehicles and heat pumps; •The integration of new, geographically-diverse energy markets; •The deployment of new technologies like energy storage, communications networks, automation and control systems for flexible loads, and distributed generation; •The development of connected neighborhood microgrids and smart communities; and •The use of data and analytics to better predict demand and support energy saving customer programs. In July 2019, PGE's Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support 38
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functions. As of December 31, 2020, the Company has recorded $109 million, including AFDC, in construction work-in-progress related to the IOC.
The Company is also working to advance transportation electrification, with projects aimed at improving accessibility to electric vehicle charging stations and partnering with local mass transit agencies to transition to a greater use of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044, which establishes Oregon's zero emissions vehicle goals in statute at 250 thousand vehicle sales by 2025 and 90% of all vehicle sales by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification plan, which considers current and planned activities, along with both existing and potential system impacts, in relation to the State's carbon reduction goals. In 2018, PGE filed an energy storage proposal that called for 39 MW of storage to be developed over the next several years at various locations across the grid. In August 2018, the OPUC issued an order that outlined an agreed approach to the development of five energy storage projects by PGE with an expected capital cost of approximately $45 million. Perform as a business-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 several such material matters. Wildfire-In 2020, Oregon experienced one of the most destructive wildfire seasons on record, with over one million acres of land burned. PGE's wildfire mitigation planning includes regular risk assessment. On September 7, 2020 PGE proactively initiated a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as the region at highest risk of wildfire. In addition to the PSPS region, PGE cut power to eight different high-risk fire areas. These actions were coordinated with emergency responders and helped clear the path for them to fight wildfires. During this time, PGE also established a community resource center within the PSPS zone to help support the residents affected. The Oregon Department of Forestry has opened an investigation into the causes of wildfires in Clackamas County. The Company has received a subpoena and is fully cooperating. The Company is not aware of any wildfires caused by PGE equipment. PGE will incur costs to replace and rebuild PGE facilities damaged by the fires, as well as addressing fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE's property and right-of-way. On October 20, 2020, the OPUC formally approved PGE's request for deferral of such costs. As of December 31, 2020, PGE deferred $15 million in costs related to wildfire response. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. Although PGE expects its 2020 regulated ROE, after adjusting for certain energy trading losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is probable of recovery as the Company's prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including an earnings review, could result in a portion, or all, of PGE's 2020 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. 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 2020 AUT included a final increase in power costs for 2020, and a corresponding increase in annual revenue requirement, of $27 million from 2019 levels, which were reflected in customer prices effective January 1, 2020. See "Power Operations" within this Overview section of Item 7 for more information regarding the PCAM. Portland Harbor Environmental Remediation Account (PHERA) Mechanism-The EPA has listed PGE as one of over one hundred PRPs related to the remediation of the Portland Harbor Superfund site. As of December 31, 2020, significant uncertainties still remained concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion. However, the Company does not currently have sufficient information to 39
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reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor, although such costs 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 environmental recovery mechanism allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as 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. Under the PHERA mechanism in 2020, PGE incurred and deferred $6 million related to defense costs, net an estimated refund of less than $1 million as a result of the regulated earnings test. PGE's results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or disallowed per the prescribed earnings test. For further information regarding the PHERA mechanism, see "EPA Investigation of Portland Harbor" in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data." City of Portland Audit-In 2019, the city of Portland (the "City"), which is the largest city within PGE's service territory, completed its audit of PGE's and the City's mutual License Fees agreement for the 2012 through 2015 periods. The preliminary claim by the City is that PGE improperly excluded certain items from the calculation of gross revenues, which resulted in underpayment of franchise taxes of $7 million, including interest and penalties. PGE disagreed with the preliminary findings as they were not consistent with previous audit conclusions, which found that the Company had appropriately calculated gross revenues in determining franchise fees. In December 2020, PGE and the City reached a settlement for less than $1 million that covered the audit periods from 2012 to 2018. Capital Project Deferral-In the second quarter of 2018, PGE placed into service a new customer information system at a total cost of $152 million. In accordance with agreements reached with stakeholders in the Company's 2019 GRC, the Company's capital cost of the asset was included in rate base and customer prices as of January 1, 2019. Consistent with past regulatory precedent, in May 2018, the Company submitted an application to the OPUC to defer the revenue requirement associated with this new customer information system from the time the system went into service through the end of 2018. As a result, PGE began deferring its incurred expenses, primarily related to depreciation and amortization, of the new customer information system once it was placed in service. In 2017, the OPUC had opened docket UM 1909 to conduct an investigation of the scope of its authority under Oregon law to allow the deferral of costs related to capital investments for later inclusion in customer prices. In October 2018, the OPUC issued Order 18-423 (1909 Order) concluding that the OPUC lacked authority under Oregon law to allow deferrals of any costs related to capital investments. In the 1909 Order, the OPUC acknowledged that this decision was contrary to its past limited practice of allowing deferrals related to capital investments and would require adjustments to its regulatory practices. The OPUC directed its Staff to meet with the utilities and stakeholders to address the full implications of this decision, and to propose recommendations needed to implement this decision consistent with the OPUC's legal authority and the public interest. During 2018, PGE deferred a total of $12 million of expenses related to the customer information system. However, the 1909 Order impacted the probability of recovery of deferred expenses and, as such, the Company recorded a reserve for the full amount of the costs related to the customer information system. The reserve was established with an offsetting charge to the results of operations in 2018. In response to the 1909 Order, PGE and other utilities filed a motion for reconsideration and clarification, which was denied. On April 19, 2019, PGE and the other utilities filed a petition for judicial review of the 1909 Order with the Oregon Court of Appeals, although the Court has indicated that the case would be dismissed given the lack of recent action in the case.
On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility's capital projects, including both depreciation expense and the cost of financing capital projects. PGE
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believes that the costs incurred to date associated with the customer information system were prudently incurred; however, PGE intends to file to close the deferral proceeding related to the customer information system without further action at the OPUC.
Decoupling-The decoupling mechanism, authorized by the OPUC through 2022, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than that projected in the Company's most recent general rate case. The Company recorded an estimated refund of $15 million and a collection of $9 million from residential and commercial customers, respectively for the year ended December 31, 2020, which 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 COVID-19. Collections under the decoupling mechanism are subject to an annual limitation of 2% of revenues for each eligible customer class, based on the net prices in effect for the applicable tariff schedule at the time of collection. For collections recorded in 2020, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2022. The Company reached its 2020 annual cap for collection from commercial customers during the third quarter of 2020. No cap exists for any potential refunds under the decoupling mechanism, thus increased demand from residential customers since the onset of the COVID-19 pandemic has resulted in larger estimated refunds under the decoupling mechanism, which have largely offset the revenue increases that have resulted from higher residential demand. Any collection from customers for the 2020 year is expected to occur over a one-year period, which would begin January 1, 2022.
At December 31, 2019, PGE had recorded a total collection of $14 million that will be collected over a one-year period, which began January 1, 2021.
Corporate Activity Tax-In 2019, the state of Oregon enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million and applies to tax years beginning on or after January 1, 2020. The tax applies to commercial activities sourced in Oregon, less a deduction for 35% of the greater of "cost inputs" or "labor costs." The resulting amount is taxed at 0.57%. In January 2020, at PGE's request, the OPUC issued an order approving a tariff and related deferral and balancing account to provide for an estimated recovery of $7 million in customer prices in 2020. The Company will revisit the expected tax consequences annually and revise the annual tariff accordingly. Pursuant to the order, PGE started collections in customer prices February 1, 2020. For the year ended December 31, 2020, PGE incurred $8 million under the tax. Non-utility Asset Retirement Obligation (ARO)-PGE's Non-utility ARO represents the liability that has been recognized for portions of unregulated properties that are currently or previously leased to third parties and located adjacent to PGE's T.W. Sullivan hydro generating facility. In 2020, PGE performed a decommissioning study to update its ARO liability which resulted in a $21 million increase to non-utility property AROs. Additions in non-utility AROs related to assets that are no longer in service are charged directly to Depreciation and amortization on the consolidated statements of income in the period in which the revisions are probable and reasonably estimable. As a part of this study, the Company also established an additional ARO liability of $3 million related to utility properties that was charged to Depreciation and amortization expense. PGE plans to pursue regulatory recovery for the utility portion of the ARO update, however, as of December 31, 2020, no amounts have been deferred as a regulatory asset. For further information regarding the Company's AROs, see Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data." Deferral of Boardman Revenue Requirement-In October 2020, intervenors filed a deferral application with the OPUC that would require PGE to defer and refund the revenue requirement associated with Boardman currently 41
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included in customer prices as established in the Company's last general rate case. The application states a deferral is required for customers to adequately capture the reduction in revenue requirement beginning on October 15, 2020, the date Boardman ceased operations. PGE estimates this amount could be up to $14 million for the period ended December 31, 2020. As of December 31, 2020, PGE has not recorded a regulatory liability pursuant to this deferral application as the Company believes its current prices are just and reasonable in light of PGE's continued substantial investments in utility plant. The costs of these investments, which are not currently reflected in customer prices, more than offsets the revenue requirement for Boardman. If the OPUC authorizes the deferral, PGE would record a regulatory liability with a corresponding charge to earnings. 2021 Storm- Beginning on February 11, 2021, an historic set of storms involving heavy snow, winds, and ice impacted the United States, including PGE's service territory. Significant damage across the State of Oregon led Oregon's Governor to call a state of emergency on February 13, 2021. PGE's restoration efforts in response to this historic set of storms are ongoing and the total costs of the storm cannot be reasonably estimated, although such costs could be material to its results of operations in 2021. Given the magnitude of the impacts to PGE's transmission and distribution system, on February 15, 2021 PGE filed a deferral application with the OPUC for potential recovery of restoration costs, however, there is no assurance that such recovery would be granted by the OPUC. 42
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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. PGE also participates in the CAISO western EIM, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United States and Canada to fuel its generation portfolio and sells excess gas back into the wholesale market. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to its retail customers. The impact of seasonal weather conditions on demand for electricity can cause the Company's revenues, cash flows, and income from operations to fluctuate from period to period. Historically, PGE has experienced its highest MWa deliveries and retail energy sales during the winter heating season, although instances of peak deliveries have increased during the summer months, generally resulting from air conditioning demand. See "Seasonality" in the Customers and Revenues section in Item 1.-"Business." for further information regarding seasonal fluctuations. 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 2020 and 2019.
Energy deliveries (MWh in thousands) 2020 2019 (Decrease) Retail: Residential 7,756 7,471 3.8 % Commercial (PGE sales only) 6,222 6,653 (6.5) Direct Access 633 665 (4.8) Total Commercial 6,855 7,318 (6.3) Industrial (PGE sales only) 3,446 3,181 8.3 Direct Access 1,486 1,490 (0.3) Total Industrial 4,932 4,671 5.6 Total (PGE sales only) 17,424 17,305 0.7 Total Direct Access 2,119 2,155 (1.7) Total retail energy deliveries 19,543 19,460 0.4 % Wholesale energy deliveries 5,794 4,669 24.1 Total energy deliveries 25,337 24,129 5.0 % Average number of retail customers 2020 2019 % Increase Residential 791,119 88 % 779,673 88 % 1.5 % Commercial 110,290 12 109,521 12 0.7 Industrial 194 - 193 - 0.5 Direct access 634 - 632 - 0.3 Total 902,237 100 % 890,019 100 % 1.4 % In 2020, retail energy deliveries increased 0.4% from 2019. While results for the first quarter largely reflected conditions prior to the COVID-19 pandemic, the remainder of the year was influenced by customer behavioral response to the pandemic. 43
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On March 23, 2020, the Governor of Oregon issued an order directing residents to stay at home except for essential activity and mandating closure of businesses for which close personal contact would be difficult or impossible to avoid. The Company saw a shift in retail demand in response, beginning with the second quarter of 2020. In particular, residential loads increased as a larger percentage of the population spent more time at home, whether working from home, providing child-care due to school closures, or lacking employment as commercial activity slowed. Conversely, commercial energy deliveries declined as many businesses were disrupted in an attempt to maintain social distancing or have closed as a result of the lack of business as residents followed directives from state and federal authorities. Although the industrial class as a whole experienced an increase in energy deliveries for 2020, this was due primarily to continued growth in the high-tech and digital services sectors, which saw lesser impacts from noted closures than other sectors. Residential energy deliveries, which are most sensitive to fluctuations in temperatures, were 3.8% higher in 2020 than 2019, due to a 2.3% increase in average usage per customer and a 1.5% increase in the average number of customers. Residential deliveries, down 6% in the first quarter driven by mild temperatures, were up 9% in the second quarter of 2020 due largely to the impact of the COVID-19 pandemic and have remained strong through the balance of the year. Commercial energy deliveries declined 6.3% overall with widespread decreases across PGE's customer base led by several sectors most impacted by COVID-19 related closures and economic conditions, including: government and education; offices, finance, insurance, and real estate; and restaurants and lodging. The 5.6% increase during 2020 in industrial energy deliveries is due to continued strength in the high-tech manufacturing sector as well as a full-year of demand from a large paper facility that reopened during 2019, after having closed in late 2017. In 2020, the Company's service territory experienced warmer temperatures during the heating season than in 2019, indicating lower demand for heating, the effect of which was partially offset by having slightly warmer temperatures during the summer cooling season and increased demand for cooling. Total heating degree-days, an indication of electricity use for heating, in 2020 were 7% below the 15-year average and down 8% from total heating degree-days in 2019. Total cooling degree-days, a similar indication of the extent to which customers are likely to have used electricity for cooling, in 2020, exceeded the 15-year average by 12% and were 6% above the 2019 total. The following table presents the number of heating and cooling degree-days in 2020 and 2019, along with the current 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries: Heating Degree-Days Cooling Degree-Days 2020 2019 15-Year Average 2020 2019 15-Year Average 1st quarter 1,761 1,992 1,848 - - - 2nd quarter 554 467 636 99 102 89 3rd quarter 47 83 78 492 462 447 4th quarter 1,474 1,623 1,583 9 - 2 Total 3,836 4,165 4,145 600 564 538 Increase (decrease) from the 15-year average (7) % - % 12 % 5 % On a weather-adjusted basis, total retail deliveries increased 1.5% from 2019. The increase was driven by 6.3% growth in residential deliveries and 5.6% growth in industrial energy deliveries, which were somewhat offset by a decrease in commercial energy deliveries of 6.0%. Retail energy deliveries for 2021 will continue to be impacted by COVID-19 related behavioral changes. PGE projects that retail energy deliveries for 2021 will be approximately 44
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1.0% - 1.5% above 2020 weather-adjusted levels, reflecting strength in industrial deliveries, and impacts associated with COVID-19 early in the year, and unwinding of such impacts later in the year.
ESSs supplied Direct Access customers with energy representing 11% of the Company's total retail energy deliveries during 2020 and 2019. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 13% of the Company's total retail energy deliveries for 2020, and 2019. With the adoption of the New Large Load Direct Access program in 2020, as much as 19% of the Company's energy deliveries could have been supplied by ESSs. Energy efficiency and conservation efforts by retail customers influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism, which is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts. The mechanism provides for collection from (or refund to) customers if weather-adjusted use per customer is less (or more) than the projected baseline set in the Company's most recent approved general rate case. See "Decoupling" in this Overview section of Item 7, for further information on the decoupling mechanism. Power Operations-PGE utilizes a combination of its own generating resources and wholesale market transactions to meet the energy needs of its retail customers. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, the Company continuously makes economic dispatch decisions in an effort to obtain reasonably-priced power for its retail customers. PGE also purchases wholesale natural gas in the United States and Canada to fuel its generating portfolio and sells excess gas back into the wholesale market. As a result, the amount of power generated and purchased in the wholesale market to meet the Company's retail load requirement can vary from period to period and impacts NVPC and income from operations.
The following table provides information regarding the performance of the Company's generation portfolio.
Actual energy provided Actual energy provided as a compared to projected percentage of total retail Plant availability (1) levels (2) load 2020 2019 2020 2019 2020 2019 Thermal: Natural gas 92 % 92 % 74 % 86 % 43 % 45 % Coal (3) 99 87 83 104 17 24 Wind 94 96 117 90 11 9 Hydro 86 93 71 81 7 8 (1)Plant availability represents the percentage of the year plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2)Projected levels of energy are included as part of PGE's AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources. (3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 74% in 2020, compared with 85% in 2019. Boardman ceased coal-fired generation on October 15, 2020. Energy received from PGE-owned and jointly-owned thermal plants decreased 12% in 2020 compared to 2019, primarily as a result of a 27% reduction in generation from coal-fired generation, which produced only 13% of the Company's total system load in 2020. 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. 45
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Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, increased 12% in 2020 compared to 2019. While energy received from mid-Columbia hydroelectric projects increased 46% in 2020, the energy generated by the Company-owned facilities decreased 14%. 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 7, for further detail on regional hydro results. Energy received from PGE-owned wind resources and under contracts increased 28% in 2020 compared to 2019, due to more favorable wind conditions in 2020 and the addition of Wheatridge during the fourth quarter 2020. Energy expected to be received from Biglow Canyon and Tucannon River is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation increase, a larger amount of PTCs were produced in 2020 than in 2019 and exceeded what was contemplated in the Company's prices. For Wheatridge, wind generation studies were used to develop NVPC cost forecasts, which were included in the RAC filing for the facility, and included in customer prices when the facility went into service. The RAC tariff included NVPC in 2020 along with all other aspects of the revenue requirement. Beginning January 1, 2021, the NVPCs were included in the Company's AUT, although the other aspects of the RAC tariff will remain in effect until they are included in customer prices as a result of a future general rate case. Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Customer prices can be adjusted annually to absorb a portion of the difference between the forecasted NVPC included in customer prices (baseline NVPC) and actual NVPC for the year, if such differences exceed a prescribed "deadband" limit, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE's actual regulated return on equity (ROE) for the given year being no less than 1% above the Company's latest authorized ROE, while a collection will occur only to the extent that it results in PGE's actual regulated ROE for that year being no greater than 1% below the Company's authorized ROE. The following is a summary of the results of the Company's PCAM as calculated for regulatory purposes for 2020, and 2019: •For 2020, actual NVPC, excluding certain trading losses totaling $127 million, was below baseline NVPC by $13 million, which was within the established deadband range, so no estimated refund to customers was recorded as of December 31, 2020. A final determination regarding the 2020 PCAM results will be made by the OPUC through a public filing and review in 2021. If actual NVPC for 2020 included the certain trading losses, it would have been $114 million above the baseline. See "Energy Trading" in the Overview section of this Item 7. for further information regarding certain trading losses. •For 2019, actual NVPC was above baseline NVPC by $5 million, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded as of December 31, 2019. A final determination regarding the 2019 PCAM results was made by the OPUC through a public filing and review in 2020, which confirmed no refund to customers pursuant to the PCAM for 2019.
The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $27 million increase was expected in 2020 over 2019. The 2021 AUT anticipates a $79 million increase in NVPCs that will be recovered in customer prices beginning January 1, 2021.
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.
PGE defines Gross margin as Total revenues less Purchased power and fuel. Gross margin is considered a non-GAAP measure as it excludes depreciation and amortization and other operation and maintenance expenses. The presentation of Gross margin is intended to supplement an understanding of PGE's operating performance in 46
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relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company's definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.
The results of operations are as follows for the years presented (dollars in millions): Years Ended December 31, 2020 2019 % Increase Amount Amount (Decrease) Total revenues (1) $ 2,145 $ 2,123 1 % Purchased power and fuel (1) 708 614 15 Gross margin 1,437 1,509 (5) Other operating expenses: Generation, transmission and distribution 293 323 (9) Administrative and other 283 290 (2) Depreciation and amortization 454 409 11 Taxes other than income taxes 138 134 3 Total other operating expenses 1,168 1,156 1 Income from operations 269 353 (24) Interest expense, net (2) 136 128 6 Other income: Allowance for equity funds used during construction 16 10 60 Miscellaneous income, net 6 6 - Other income, net 22 16 38 Income before income taxes 155 241 (36) Income tax (benefit) expense - 27 (100) Net income $ 155 $ 214 (28) %
(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE's Consolidated Statements of Income. (2) Includes an allowance for borrowed funds used during construction of $8 million in 2020 and $5 million in 2019.
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2020 Compared to 2019
Net income - The following items contributed to the change in Net income for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions):
Year ended December 31, 2019 $
Purchased power and fuel expense related to certain trading losses*
Purchased power and fuel expense, excluding certain trading losses*
Other operating revenues primarily from the resale of excess natural gas
used for fuel in 2019 that did not recur in 2020 Average retail price predominately due to increase under the AUT for NVPC 37 Retail deliveries, net of decoupling deferral
Wholesale revenues driven by lower average sale prices (8) Late fee revenue due largely to COVID-19 related curtailments (6)
Generation, transmission and distribution expenses driven by lower plant
Administrative and general expenses due largely to lower wages and
Non-utility ARO due to revised estimates
Depreciation and amortization resulting largely from capital additions
Income taxes resulting primarily from lower pre-tax income 27 Other (4) Year ended December 31, 2020 155 Change in Net income $ (59)
*See "Energy Trading" in the Overview section of this Item 7.-"Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information regarding certain trading losses.
Total revenues consist of the following for the years presented (in millions): 2020 2019 % Increase (Decrease) Retail: (1) Residential $ 1,030 $ 981 5 % Commercial 616 636 (3) Industrial 218 196 11 Direct Access 46 44 5 Subtotal 1,910 1,857 3 Alternative revenue programs, net of amortization (6) 2 (400) Other accrued revenues, net (2) 28 22 27 Total retail revenues 1,932 1,881 3 Wholesale revenues 162 170 (5) Other operating revenues 51 72 (29) Total revenues $ 2,145 $ 2,123 1 %
(1) Includes both revenues from customers who purchase their energy supplies from the Company
and revenues from the delivery of energy to those customers that purchase their energy from
ESSs. Commercial revenues from ESS customers were $18 million for 2020 and 2019. Industrial
revenues from ESS customers were $28 million and $26 million for 2020 and 2019,
(2) Amounts for the years ended December 31, 2020 and 2019 are primarily comprised of $24
million and $23 million of amortization, respectively, including interest, related to the
net tax benefits due to the change in corporate tax rate under the TCJA. 48
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Total retail revenues-The following items contributed to the increase in Total retail revenues for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions): Year ended December 31, 2019 $ 1,881 Retail energy deliveries driven by higher industrial demand, the impact of COVID-19 resulting in higher residential demand, and the negative effects of weather 8
Average price of energy deliveries due primarily to the AUT and the variation in usage among customer classes resulting from COVID-19
Combination of various supplemental tariffs and adjustments, the largest of which were $11 million that pertains to the demand response pilot programs, $8 million related to Boardman decommissioning, and $7 million for the Oregon Commercial Activities Tax
Alternative revenue programs related to the decoupling mechanism deferrals due to increased residential use per customer resulting from COVID-19
Amortization of prior year decoupling deferrals into customer prices
11 Year ended December 31, 2020
Change in Total retail revenues
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. In 2020, an $8 million, or 5%, decrease from 2019 in wholesale revenues resulted from a $49 million decrease from a 23% decrease in average prices received when the Company sold power into the wholesale market, partially offset by a $41 million increase related to a 24% increase in wholesale sales volume. Other operating revenues decreased $21 million, or 29%, in 2020 from 2019, primarily as a result of a $17 million decrease predominately resulting from market conditions that provided less revenue from the resale of natural gas back into the wholesale market in excess of amounts needed for the Company's generation portfolio. Natural gas prices were considerably higher in the first quarter of 2019 as a result of a supply pipeline disruption in the region. Milder than average winter temperatures in North America in 2020 resulted in an oversupply of natural gas and lower prices. In addition, a $6 million decrease occurred due to the curtailment of late fees as a result of the COVID-19 pandemic. 49
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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 increase in Purchased power and fuel for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions, except for average variable power cost per MWh): Year ended December 31, 2019 $ 614 Average variable power cost per MWh 62 Total system load 32 Year ended December 31, 2020 $ 708 Change in Purchased power and fuel $ 94 Average variable power cost per MWh: Year ended December 31, 2019 $ 26.62 Year ended December 31, 2020 $ 29.14 Total system load (MWh in thousands): Year ended December 31, 2019 23,085 Year ended December 31, 2020 24,286 For the year ended December 31, 2020, the $62 million increase related to the change in average variable power cost per MWh, was primarily driven by an 8% increase in the average cost for purchased power, partially offset by a 14% decrease on the average cost for the Company's own generation. The increase in the cost of purchased power was driven by realized losses of $127 million related to a portion of energy trading positions in PGE's energy portfolio. See "Energy Trading" in the Overview section of this Item 7., for more details. The $32 million increase related to total system load was primarily due to a 35% increase in purchased power, driven by economic dispatch decisions based on lower gas prices and surplus hydro in the region.
PGE's sources of energy, total system load, and retail load requirement for the years presented are as follows:
2020 2019 Sources of energy (MWh in thousands): Generation: Thermal: Natural gas 8,029 33 % 8,342 36 % Coal 3,232 13 4,416 19 Total thermal 11,261 46 12,758 55 Hydro 1,204 5 1,407 6 Wind 2,111 9 1,706 8 Total generation 14,576 60 15,871 69 Purchased power: Term contracts 7,741 32 5,882 25 Hydro 1,535 6 1,048 5 Wind 434 2 284 1 Total purchased power 9,710 40 7,214 31 Total system load 24,286 100 % 23,085 100 % Less: wholesale sales (5,794) (4,669) Retail load requirement 18,492 18,416 50
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The following table presents the actual April-to-September 2020 and 2019 runoff at particular points of major rivers relevant to PGE's hydro resources:
a Percent of 30-year Average
2020 2019 Location Actual Actual Columbia River at The Dalles, Oregon 104 % 94 % Mid-Columbia River at Grand Coulee, Washington 109 87 Clackamas River at Estacada, Oregon 75 114 Deschutes River at Moody, Oregon 86 111 Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $102 million in 2020 compared with 2019. The increase attributable to changes in Purchased power and fuel expense was the result of a 9% increase in the average variable power cost per MWh and a 5% increase in total system load. In addition, wholesale energy deliveries decreased $8 million from the net of 23% lower average price per MWh sold, partially offset by a 24% increase in the volume of wholesale energy deliveries. The following items contributed to the increase in Actual NVPC for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions): Year ended December 31, 2019 $ 444 Purchased power and fuel expense 94 Wholesale revenues 8 Year ended December 31, 2020 546 Change in NVPC $ 102
For further information regarding NVPC in relation to the PCAM, see "Power Operations" in the Overview section of this Item 7.
Generation, transmission, and distribution
The following items contributed to the $30 million or 9% decrease in Generation, transmission and distribution for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions): Year ended December 31, 2019 $ 323 Decrease primarily due to lower maintenance expense as the result of
reduced run hours and lower long-term service agreement costs at some of the Company's generation facilities Lower utilization of contract labor and higher capitalization rates
(8) Miscellaneous expenses (2) Year ended December 31, 2020
Change in Generation, transmission and distribution
For the year ended December 31, 2020, PGE deferred $15 million of incremental costs related to wildfires in PGE's service territory. See "Wildfires" within "Perform as a business" under "Company Strategy" in the Overview section of this Item 7., for more information. 51
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Administrative and other
The following items contributed to the $7 million or 2% decrease in Administrative and other for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions):
Year ended December 31, 2019 $ 290 Wage and benefits expenses (12) Bad debt expense 5 Year ended December 31, 2020 283 Change in Administrative and other $ (7)
As of December 31, 2020, PGE has deferred $8 million of bad debt related to incremental expense incurred related to COVID-19 as part of the OPUC's Energy Term Sheet. See the "Overview" section of this Item 7., for more information.
Depreciation and amortization
The following items contributed to the $45 million or 11%, increase in Depreciation and amortization for the year ended December 31, 2020 compared to year ended December 31, 2019 (in millions):
Year ended December 31, 2019 $ 409 ARO revisions 24 Activity related to regulatory programs (offset in revenues) 13 Capital additions 8 Year ended December 31, 2020 454 Change in Depreciation and amortization $ 45
See "Non-utility Asset Retirement Obligation Overview" within "Perform as a business" under "Company Strategy" in the Overview section of this Item 7., for more information regarding revisions made to non-utility AROs.
Taxes other than income taxes expense increased $4 million, or 3%, in 2020 compared with 2019, primarily due to higher Oregon property taxes.
Interest expense increased $8 million, or 6%, in 2020 compared with 2019 due to higher average balances of outstanding debt as well as increased interest on finance leases.
Other income, net increased $6 million, or 38%, in 2020 compared to 2019, with the difference due to higher AFDC equity driven by higher construction work-in-progress balances in 2020.
Income tax expense decreased $27 million, or 100%, in 2020 compared to 2019 primarily due to lower pre-tax income in 2020, partially offset by higher expense from the Oregon Corporate Activity tax which took effect on January 1, 2020.
2019 Compared to 2018
For a comparison of the Company's results of operations for the fiscal year ended December 31, 2019 to the year ended December 31, 2018, see Item 7.-" Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 14, 2020.
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Liquidity and Capital Resources
Discussions, forward-looking statements, and projections in this section, and similar statements in other parts of this Annual Report on Form 10-K, are subject to PGE's assumptions regarding the availability and cost of capital. See "Capital and credit market conditions could adversely affect the Company's access to capital, cost of capital, and ability to execute its strategic plan as currently envisioned." in Item 1A.-"Risk Factors," for further information.
The following table presents actual capital expenditures and debt maturities for 2020 and projected capital expenditures and future debt maturities for 2021 through 2025 (in millions, excluding AFDC):
Years Ending December 31, 2020 2021 2022 2023 2024 2025 Ongoing capital expenditures* $ 568 $ 555 $ 550 $ 550 $ 550 $ 550 Integrated Operations Center 77 100 - - - - Wheatridge Renewable Energy Facility 129 - - - - - Total capital expenditures $ 774 $ 655 $ 550 $ 550 $ 550 $ 550 Long-term debt maturities $ - $ 160 $ - $ - $ 80 $ -
* Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects. Includes preliminary engineering and removal costs.
During 2020, PGE funded its capital expenditures through a combination of cash from operations in the amount of $567 million, net proceeds from the issuance of PCRBs and FMBs in the total amount of $451 million, and net short-term debt issuances in the amount of $150 million. Capital expenditures in 2021 are expected to be $655 million. PGE plans to fund the 2021 capital expenditures and long-term debt maturities with cash from operations during 2021, which is expected to range from $600 million to $650 million, the issuance of debt securities of up to $300 million, and the issuance of commercial paper, as needed. The actual timing and amount of any other issuances of debt or commercial paper will be dependent upon the timing and amount of capital expenditures. For a discussion concerning PGE's ability to fund its future capital requirements, see "Debt and Equity Financings" in the Liquidity and Capital Resources section of this Item 7.
PGE's access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company's current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, information technology systems, and debt refinancing activities. PGE's liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company's forward positions and the corresponding price curves. 53
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The following summarizes PGE's cash flows for the periods presented (in millions): Years Ended December 31, 2020 2019 Cash and cash equivalents, beginning of year $ 30 $ 119 Net cash provided by (used in): Operating activities 567 546 Investing activities (787) (604) Financing activities 447 (31) Net change in cash and cash equivalents 227
Cash and cash equivalents, end of year $ 257 $ 30 2020 Compared to 2019 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 $21 million increase in cash flows from operating activities in 2020 compared to 2019 is due to: •$59 million reduction in Net income in 2020; •$63 million increase related to additional contributions to the pension and other postretirement benefit plans in 2019 that did not recur in 2020; •$45 million increase in Depreciation and amortization primarily due to higher average plant balances and revision to non-utility AROs in 2020. See the Overview section of this Item 7., for more information regarding revisions made to non-utility AROs; •$42 million increase for Accounts payable and other accrued liabilities primarily due to the timing of payments to vendors; •$29 million increase in Other working capital, net primarily due to the use of materials and supplies and fuel inventory in the course of business; partially offset by •$54 million decrease as a result of changes in Accounts receivable and Unbilled revenue; •$29 million decrease related to Deferred income taxes; •$9 million decrease related to cash settlements for ARO liabilities; and •$7 million decrease related to other miscellaneous items.
For additional information regarding changes in Net income, see the Results of Operations section in this Item 7.
Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. The Company estimates that such charges in 2021 will range from $410 million to $430 million. Combined with all other sources, cash provided by operations in 2021 is estimated to range from $600 million to $650 million. Cash Flows from Investing Activities-Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE's distribution, transmission, and generation facilities. The $183 million increase in net cash used in investing activities in 2020 compared with 2019 is primarily due to the construction of Wheatridge and the IOC. 54
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The Company plans for $655 million of capital expenditures in 2021 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. PGE plans to fund the 2021 capital expenditures with cash from operations during 2021, as discussed above, as well as with the issuance of short- and long-term debt securities. For additional information, see "Capital Requirements" and "Debt and Equity Financings" in the Liquidity and Capital Resources section of this Item 7. Cash Flows from Financing Activities-Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During 2020, cash provided by financing activities consisted primarily of the issuance of $430 million of FMBs and $119 million of PCRBs, less the remarketing of $98 million of PCRBs. In addition, the Company issued a $150 million short-term loan and paid dividends in the amount of $140 million.
2019 Compared to 2018
For a comparison of liquidity and capital resources and the Company's cash flow activities for the fiscal year ended December 31, 2019 and 2018, see Item 7.-"Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 14, 2020.
Credit Ratings and Debt Covenants
PGE's secured and unsecured debt is rated investment grade by Moody's and S&P, with current credit ratings and outlook as follows:
Moody's S&P First Mortgage Bonds A1 A Senior unsecured debt A3 BBB+ Commercial paper P-2 A-2 Outlook Stable Stable In the event Moody's and/or S&P reduce their credit rating on PGE's unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits in PGE's consolidated balance sheets, while any letters of credit issued are not reflected in the Company's consolidated balance sheets. As of December 31, 2020, PGE had posted $20 million of collateral with these counterparties, consisting of $8 million in cash and $12 million in bank letters of credit. Based on the Company's energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of December 31, 2020, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $32 million and decreases to zero by December 31, 2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $122 million and decreases to $79 million by December 31, 2021 and $72 million by December 31, 2022. PGE's financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facilities would increase.
The Indenture securing PGE's outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of
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Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2020, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $695 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property. PGE's credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt to total capital ratio). As of December 31, 2020, the Company's debt to total capital ratio, as calculated under the credit agreements, was 56.4%.
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 significant 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. Short-term Debt-Pursuant to an order issued by the FERC on January 16, 2020, PGE has authorization to issue short-term debt up to a total of $900 million through February 6, 2022. The following table shows available liquidity as of December 31, 2020 (in millions): December 31, 2020 Capacity Outstanding Available
Revolving credit facility (1) $ 500 $ - $ 500 Letters of credit (2) 220 60 160 Total credit $ 720 $ 60 $ 660 Cash and cash equivalents 257 Total liquidity $ 917 (1)Scheduled to expire November 2023. (2)PGE has four letter of credit facilities under which the Company can request letters of credit for an original term not to exceed one year. As of December 31, 2020, PGE had a $500 million revolving credit facility scheduled to expire in November 2023. 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. 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 for general corporate purposes. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. The Company has elected to limit its borrowings under the revolving credit facility to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2020, PGE had no commercial paper outstanding. 56
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PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets.
Under the revolving credit facility, as of December 31, 2020, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2020, the aggregate unused available credit capacity under the revolving credit facility was $500 million.
In addition, PGE has four letter of credit facilities under which the Company has total capacity of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $60 million were outstanding as of December 31, 2020. On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate principal of $150 million. The term loan bears interest for the relevant interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment pursuant to the terms of the loan. The credit agreement is classified as Short-term debt on the Company's consolidated balance sheets and expires on April 8, 2021, with any outstanding balance due and payable on such date.
Long-term Debt-During 2020, PGE issued a total of $430 million of FMBs.
On April 27, 2020, PGE issued $200 million of 3.15% Series FMBs due in 2030.
On December 10, 2020, the Company issued to certain institutional buyers in the private placement market $230 million aggregate principal amount of the Company's FMBs that consisted of:
•a series, due in 2027, in the amount of $160 million that will bear interest from its issuance date at an annual rate of 1.84%; and
•a series, due in 2032, in the amount of $70 million that will bear interest from its issuance date at an annual rate of 2.32%.
Pollution Control Revenue Bonds-On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that bear an interest rate of 2.375%, both due in 2033. At the time of remarketing, the Company chose a new interest rate period that was fixed term. The new interest rate was based on market conditions at the time of remarketing. The PCRBs are backed by the Company's Indenture of Mortgage by way of FMBs. Interest is payable semi-annually on the PCRBs. As of December 31, 2020, total long-term debt outstanding, net of $13 million of unamortized debt expense, was $3,046 million, of which $160 million is scheduled to mature in 2021. Capital Structure-PGE's financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade debt ratings and provides access to long-term capital at favorable interest rates. The Company's common equity ratio was 45.0% and 49.9% as of December 31, 2020 and 2019, respectively. 57
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Contractual Obligations and Commercial Commitments
The following table presents PGE's contractual obligations as of December 31, 2020 (in millions):
There- 2021 2022 2023 2024 2025 after Total Long-term debt $ 160 $ - $ - $ 80 $ - $ 2,819 $ 3,059 Interest on long-term debt (1) 126 124 124 124 121 1,806 2,425 Capital and other purchase commitments 237 33 20 1 1 55 347 Purchased power and fuel: Electricity purchases 250 257 284 278 249 2,886 4,204 Capacity contracts 9 9 9 9 9 - 45 Public Utility Districts 21 19 18 17 17 39 131 Natural gas 57 42 37 43 43 578 800 Coal and transportation 27 27 27 27 27 - 135 Pension Plan Contributions (2) - - 16 23 23 - 62
Finance and operating lease obligations 24 24 22
21 14 267 372 Total $ 911 $ 535 $ 557 $ 623 $ 504 $ 8,450 $ 11,580 ` (1) Future interest on long-term debt is calculated based on the assumption that all debt remains outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect as of December 31, 2020. (2) Contributions beyond 2025 are not estimated due to significant uncertainty in financial market and demographic outcomes.
Other Financial Obligations
PGE has long-term power purchase agreements in place with certain public utility districts in the state of Washington.
The Company has acquired a percentage of the output of the Priest Rapids and Wanapum Hydroelectric Projects under an agreement that requires PGE to pay its proportionate share of the operating and debt service costs of the projects, whether or not they are operable. The agreements further provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro-rata share of both the output and the operating and debt service costs of the defaulting purchaser. Under an agreement for output of Douglas County PUD's Wells Hydroelectric Project, PGE receives a share of the production in return for a fixed payment. If any other purchaser of output were to default, PGE would receive a pro-rata portion of the defaulting purchaser's share of the project output and associated costs, with no limitation, regardless of the reason for the default. The share of the project output is expected to decline over time as the public utility district load grows and output is needed to serve that growth. For additional information on these long-term power purchase agreements, see "Public utility districts" in Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data."
Off-Balance Sheet Arrangements
Other than the items listed below, PGE has no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on its consolidated financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources: 58
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•PGE has four letter of credit facilities that provide capacity up to a total of $220 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, $60 million has been issued as of December 31, 2020; and •As a co-owner of Colstrip, PGE has provided surety bonds of $30 million as of December 31, 2020 on behalf of the operator to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station, Colstrip Montana (the AOC) as required by the Montana Department of Environmental Quality. It is possible that each co-owner of Colstrip will be required, at some future point, to post additional financial assurance to support further performance by the operator of closure and remediation actions under the AOC.
Critical Accounting Policies and Estimates
The preparation of consolidated financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect amounts reported in the statements. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions, and judgments to determine matters that are inherently uncertain. Regulatory Accounting As a rate-regulated enterprise, PGE applies regulatory accounting, which includes the recognition of regulatory assets and liabilities on the Company's consolidated balance sheets. Regulatory assets represent probable future revenue associated with certain incurred costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited or refunded to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established or subject to approval by independent third-party regulators, prices are designed to recover the specific enterprise's cost of service, and, in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Amortization of regulatory assets and liabilities is reflected in the statement of income over the period in which they are included in customer prices. If future recovery of regulatory assets is not probable, PGE would expense such items in the period such determination is made. Further, if PGE determines that all or a portion of its utility operations no longer meet the criteria for continued application of regulatory accounting, the Company would be required to write off those regulatory assets and liabilities related to operations that no longer meet requirements for regulatory accounting. Discontinued application of regulatory accounting would have a material impact on the Company's results of operations and financial position.
Asset Retirement Obligations
PGE recognizes AROs for legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Upon initial recognition of AROs that are measurable, the probability-weighted future cash flows for the associated retirement costs, discounted using a credit-adjusted risk-free rate, are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Due to the long lead time involved, a market-risk premium cannot be determined for inclusion in future cash flows. In estimating the liability, management must utilize significant judgment and assumptions in determining whether a legal obligation exists to remove assets. Other estimates may be related to lease provisions, ownership agreements, licensing issues, cost estimates, inflation, and certain legal requirements. Estimates for ARO liabilities are generally based on site-specific studies and are periodically subject to updates and changes that may arise over time.
Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions
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to ARO liabilities in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Accretion of the ARO liability is classified as Depreciation and amortization expense in the consolidated statements of income. Accumulated asset retirement removal costs that do not qualify as AROs have been reclassified from accumulated depreciation to regulatory liabilities in the consolidated balance sheets. Contingencies PGE has various unresolved legal and regulatory matters about which there is inherent uncertainty, with the ultimate outcome contingent upon several factors. Such contingencies are evaluated using the best information available. A loss contingency is accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, and the amount of the loss can be reasonably estimated. If a range of probable loss is established, the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. If the probable loss cannot be reasonably estimated, no accrual is recorded, but the loss contingency and the reasons to the effect that it cannot be reasonably estimated are disclosed. Material loss contingencies are disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred. Established accruals reflect management's assessment of inherent risks, credit worthiness, and complexities involved in the process. There can be no assurance as to the ultimate outcome of any particular contingency.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. Any variations in the Company's market risk or credit risk may affect its future financial position, results of operations, or cash flows, as discussed below.
Energy Risk Management
During 2020, PGE had a Risk Management Committee (RMC), whose responsibilities included providing oversight of the adequacy and effectiveness of corporate policies, guidelines, and procedures for market and credit risk management related to the Company's energy portfolio management activities. The RMC consisted of officers and Company representatives with responsibility for risk management, finance and accounting, information technology, utility operations, legal, and rates and regulatory affairs. The RMC reviewed and approved adoption of policies and procedures, and monitored compliance with policies, procedures, and limits on a regular basis through reports and meetings. The RMC also reviewed and recommended risk limits that were subject to approval by PGE's Board of Directors. In response to the energy trading losses realized in the third quarter of 2020 (for more information see "Energy Trading" in the Overview section in Item 7.-"Management's Discussion and Analysis of Financial Condition and Results of Operations.") the Company began taking actions to enhance oversight of energy trading and associated risk management reporting, policies, and practices. As a result, effective February 1, 2021, the RMC has been subsumed by the Executive Risk Committee (ERC) whose primary purpose is to oversee, guide, and support the prudent management of the Company's risks. In addition to assuming the responsibilities previously held by the RMC, the ERC's responsibilities have been enhanced to include improved risk reporting to ensure greater visibility into portfolio risk and manage alignment with the Company's Board-approved risk strategy and tolerances. Commodity Price Risk PGE is exposed to commodity price risk as its primary business is to provide electricity to its retail customers. The Company engages in price risk management activities to manage exposure to volatility in net power costs for its retail customers. The Company uses power purchase and sale contracts to supplement its own generation and to respond to fluctuations in the demand for electricity and variability in generating plant operations. The Company also enters into contracts for the purchase and sale of fuel for the Company's natural gas- and coal-fired generating 60
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plants. These contracts for the purchase of power and fuel expose the Company to market risk. The Company uses instruments such as: i) forward contracts, which may involve physical delivery of an energy commodity; ii) financial swap and futures agreements, which may require payments to, or receipt of payments from, counterparties based on the differential between a fixed and variable price for the commodity; and iii) option contracts to mitigate risk that arises from market fluctuations of commodity prices. The Company does not intend to engage in trading activities for non-retail purposes. A portion of PGE's energy portfolio subject to commodity price risk experienced significant losses during the third quarter of 2020. In August 2020, wholesale electricity prices increased substantially at various market hubs due to extreme weather conditions, constraints to regional transmission facilities, and changes in power supply in the West. As a result of the convergence of these conditions, the Company's energy portfolio experienced realized losses of $127 million in the third quarter of 2020. PGE no longer has net market exposure related to these positions and will not pursue regulatory recovery of the related losses. For additional information see "Energy Trading" in the Overview section in Item 7.-"Management's Discussion and Analysis of Financial Condition and Results of Operations." Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized (gains)/losses recorded as of December 31, 2020 related to PGE's derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2021 2022 2023
2024 2025 Thereafter Total
Commodity contracts: Electricity $ 9 $ 4 $ 8 $ 8 $ 9 $ 100 $ 138 Natural gas (27) (5) - - - - (32) Net unrealized (gain)/loss $ (18) $ (1) $ 8 $ 8 $ 9 $ 100 $ 106 PGE reports energy commodity derivative fair values as a net asset or liability, which combines purchases and sales expected to settle in the years noted above. Energy commodity fair values exposed to commodity price risk are primarily related to purchase contracts, which are slightly offset by sales. PGE's energy portfolio activities are subject to regulation, with related costs included in retail prices approved by the OPUC. The timing differences between the recognition of gains and losses on certain derivative instruments and their realization and subsequent recovery in prices are deferred as regulatory assets and regulatory liabilities to reflect the effects of regulation, significantly mitigating commodity price risk for the Company. As contracts are settled, these deferrals reverse and are recognized as Purchased power and fuel in the statements of income and expected to be included in the PCAM. PGE remains subject to cash flow risk in the form of collateral requirements based on the value of open positions and regulatory risk if recovery is disallowed by the OPUC. PGE attempts to mitigate both types of risks through prudent energy procurement practices.
Foreign Currency Exchange Rate Risk
PGE is exposed to foreign currency risk associated with natural gas forward and swap contracts denominated in Canadian dollars. Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PGE mitigates its exposure to fluctuations in the Canadian exchange rate with an appropriate hedging strategy. As of December 31, 2020, a 10% change in the value of the Canadian dollar would result in an immaterial change in exposure for transactions that will settle over the next twelve months. 61
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Interest Rate Risk
To meet short-term cash requirements, PGE has the ability to issue commercial paper for terms of up to 270 days and has a revolving credit facility that permits same day borrowings. Although any borrowings under the commercial paper program or the revolving credit facility carry a fixed rate during their respective terms, the short-term nature of such borrowings subjects the Company to fluctuations in interest rates that result from changes in market conditions. As of December 31, 2020, PGE had no borrowings outstanding under its revolving credit facility and no commercial paper outstanding. PGE currently has no financial instruments to mitigate risk related to changes in short-term interest rates, including those on commercial paper; however, it may consider such instruments in the future as considered necessary. As of December 31, 2020, the total fair value and carrying amounts, excluding unamortized debt expense, by maturity date of PGE's long-term debt are as follows (in millions): Total Carrying Amounts by Maturity Date Fair There- Value Total 2021 2022 2023 2024 after First Mortgage Bonds $ 3,683 $ 2,940 $ 160 $ - $ - $ 80 $ 2,700 Pollution Control Revenue Bonds 125 119 - - - - 119 Total $ 3,808 $ 3,059 $ 160 $ - $ - $ 80 $ 2,819
As of December 31, 2020, PGE had no long-term debt instruments subject to interest rate risk exposures.
PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. The Company manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. PGE also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded as needed to reflect credit risk related to wholesale accounts receivable. The large number and diversified base of residential, commercial, and industrial customers, combined with the Company's ability to discontinue service, contribute to reduce credit risk with respect to trade accounts receivable from retail sales. Estimated provisions for uncollectible accounts receivable related to retail sales are provided for such risk. As of December 31, 2020, PGE's credit risk exposure is $48 million for commodity activities, of which $46 million is with externally-rated investment grade counterparties. The underlying transactions that make up the exposure will mature from 2021 to 2024. The exposure is included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. Investment grade counterparties include those with a minimum credit rating on senior unsecured debt of Baa3 (as assigned by Moody's) or BBB- (as assigned by S&P), and also those counterparties whose obligations are guaranteed or secured by an investment grade entity. The credit exposure includes activity for electricity and natural gas forward, swap, and option contracts. Posted collateral may be in the form of cash or letters of credit, and may represent prepayment or credit exposure assurance.
Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington. These contracts currently provide PGE with a percentage share of hydro
T a b l e o f C o n t e n t s
facility output in exchange for an equivalent percentage share of operating and debt service costs. These contracts expire at varying dates through 2052. For additional information, see "Public utility districts" in Note 16, Commitments and Guarantees, in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data." Management believes that circumstances that could result in the nonperformance by these counterparties are remote.