PORTLAND GENERAL ELECTRIC CO /OR/ - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.
- Apr 30, 2021 8:56 am GMTApr 30, 2021 2:45 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 Electricity Service Suppliers (ESSs) or community choice aggregators; •the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to the Condensed Consolidated Financial Statements; •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; •complications arising from PGE's jointly-owned plant, including changes in ownership, adverse regulatory outcomes or legislative actions, or operational failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs; 31 -------------------------------------------------------------------------------- Table of Contents •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, ice, 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 of PGE's Board of Directors 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. 32 -------------------------------------------------------------------------------- Table of Contents Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors or assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. The MD&A should be read in conjunction with the Company's condensed consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC. PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon. In addition, the Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.
February 2021 Ice Storms and Damage
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. On February 13, 2021, Oregon's Governor declared a state of emergency due to severe winter weather that resulted in heavy snow and ice accumulation, high winds, critical transportation failures, and loss of power and communications capabilities. The wind and ice from the storms caused significant damage to PGE's transmission and distribution systems, which resulted in over 750,000 outages, with many customers affected more than once. At peak activity during the recovery, PGE deployed over 400 repair crews across the service territory, with many of these crews provided through mutual aid arrangements from throughout the West. Through March 31, 2021, PGE has incurred an estimated $87 million in incremental costs due to the storms, of which $33 million were capital and recorded to Electric utility plant, net and $54 million were operating expenses associated with transmission and distribution. Beginning in 2019, the OPUC authorized the Company to collect $4 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. In response to the February storms, PGE exhausted its storm collection balance for 2021 of $9 million, which was used to offset operating expenses. After accounting for storm deferral tracking mechanisms already in place, the cumulative incurred operating expenses from the February storm damage are estimated to be $45 million as of March 31, 2021. On February 15, 2021, PGE filed an application for authorization to defer emergency restoration costs for the February storms (Docket UM 2156) and as of March 31, 2021, the Company has deferred a total of $41 million related to incremental operating expenses due to the storm. PGE expects to incur and defer additional costs subsequent to the storm related to replacing and rebuilding PGE facilities damaged by the storm, as well as addressing vegetation and other resulting debris and hazards both in and outside of PGE's property and right-of-way. PGE does not expect an OPUC decision on the February storm deferral until sometime during 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE's prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery which could result in a portion or all of PGE's deferral being disallowed for recovery.
33 -------------------------------------------------------------------------------- Table of Contents PGE remains committed to achieving 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 greenhouse gas 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 greenhouse gas emissions associated with the power served to customers by 80% by 2030 (2010 baseline year), setting an aspirational goal for zero greenhouse gas 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 greenhouse gas 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 meet its greenhouse gas emission reduction goals. The Climate Pledge-On April 21, 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement's goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report greenhouse gas emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets. 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 implemented a new customer service 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 provides business customers access to bundled renewable attributes from those resources. On March 29, 2021, the OPUC issued an order that expanded the program by 200 MW and provided for the possibility of PGE ownership of the underlying renewable resources under certain conditions. Through this voluntary program, the Company seeks to align sustainability goals, cost and risk management, reliable integrated power, and a cleaner energy system. Carbon Legislation and Administrative Actions-In 2016, Oregon Senate Bill (SB) 1547 set a benchmark for how much electricity must come from renewable sources like wind and solar and required the elimination of coal from Oregon utility customers' energy supply no later than 2030 (subject to an exception that allowed extension of this date until 2035 for PGE's output from Colstrip). 34 -------------------------------------------------------------------------------- Table of Contents Other provisions of the law include: •An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040; •A limitation on the life of renewable energy credits (RECs) generated from facilities that become operational after 2022 to five years, but continued unlimited lifespan for all existing RECs and allowance for the generation of additional unlimited RECs for a period of five years for projects online before December 31, 2022; and •An allowance for energy storage costs related to renewable energy in the Company's Renewable Adjustment Clause (RAC) filings. In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE's investment in 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 those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2. Although PGE is currently scheduled to recover the costs of Colstrip generation 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 stretch from eastern Montana to near the western end of the state to serve markets in the Pacific Northwest and neighboring states. PGE has a 15% ownership interest in, and capacity on, the Colstrip Transmission facilities. Renewable energy development in the state of Montana might benefit from any excess transmission capacity that may become available.
As previously planned, in October 2020, PGE ceased coal-fired operation at its Boardman generating plant and has begun decommissioning activities.
After the failure of comprehensive cap and trade legislation in both the 2019 and 2020 Oregon legislative sessions, in March 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate greenhouse gas (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. •Directed state agencies to integrate climate change and the State's GHG 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 reductions and zero emission vehicle goals; and 35 -------------------------------------------------------------------------------- Table of Contents •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 (DEQ) 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 resource 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 average megawatts (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 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 production tax credits (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 continues on the solar and battery components, which are expected to be placed in service at the end of 2021.
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; •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
36 -------------------------------------------------------------------------------- Table of Contents combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage. PGE and Douglas County Public Utility District (PUD) entered into 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 MW toward a capacity need that PGE identified in its 2019 IRP. The agreement is a further step toward the Company's stated decarbonization goals. 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. At the April 20, 2021 special public meeting, the OPUC approved a motion to adopt, with supplements, the OPUC staff's recommendation to acknowledge PGE's 2019 IRP Update, with a written order to follow. The Company has begun the process to select an independent evaluator for the upcoming RFP. This is the first step toward the RFP, which is expected to continue into 2022 before finalization, with the Company planning to submit a benchmark resource into the competitive process. Renewable Recovery Framework-As previously authorized by the OPUC, a primary method available to recover costs associated with renewable resources is the Renewable Adjustment Clause (RAC). The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made by April 1st each year. In the 2019 General Rate Case (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. There have been no significant filings made under the RAC during 2021. 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 functions. As of March 31, 2021, the Company has recorded $132 million, including AFDC, in construction work-in-progress related to the IOC. The project is expected to be placed in-service in the fourth quarter of 2021. 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 electric vehicle sales by 2025 and 90% of all new vehicle sales to be electric by 2035. In September 2019, PGE filed with the OPUC its first Transportation Electrification 37 -------------------------------------------------------------------------------- Table of Contents 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 October 2020, the OPUC approved the plan and the Company began deferral accounting for costs and revenues associated with the Transportation Electrification and Electric Vehicle Charging pilot programs. 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. COVID-19 Impacts-The COVID-19 pandemic has had a variety of adverse impacts on economic activity. The Company has responded to the hardships many customers are facing and has taken steps to support its customers and communities, including temporarily suspending disconnections and late fees during the crisis, developing time payment arrangements, and partnering with local non-profits to soften the impacts on small businesses and low-income residential customers. As a result of these activities and economic hardships, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs. On March 20, 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. The application requested the ability to defer incremental costs associated with the COVID-19 pandemic but did not specify the precise scope of the deferral, or the means by which PGE would recover deferred amounts. PGE, other utilities under the OPUC's jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities which may qualify for deferral under Docket UM2114, 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 a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE's deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. For the three months ended March 31, 2021, PGE recorded no increase to its COVID-19 deferral. As of March 31, 2021 and December 31, 2020, PGE's deferred balance was $10 million, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. PGE expects incremental bad debt expense to be $6 million to $8 million for the year-ended 2021. All other incremental expenses will be recognized in the results of operations, until a determination is made that cost recovery is probable. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test. 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. 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 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 to utilities that issued short-term debt in response to the COVID-19 emergency and the detrimental impacts the issuance of short-term debt has 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. On February 23, 2021, FERC issued an order extending the waiver an additional seven months, to be effective March 1, 2021 through September 30, 2021. PGE adopted the waiver extension.
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 system-wide risk assessment,
38 -------------------------------------------------------------------------------- Table of Contents which led to the identification and activation of a public safety power shutoff (PSPS) in a zone near Mt. Hood that was identified as a region at high risk of wildfire in 2020. Additionally, in response to wildfires across Oregon in 2020, PGE cut power to eight additional high-risk fire areas in partnership with local and regional agencies. The Company is intensifying efforts on its system to increase wildfire safety and resiliency to weather and other disaster-related crises. These efforts include enhanced tree and brush clearing, replacing equipment, and making emergency plans in close partnership with local, state, and federal land and emergency management agencies to further expand the use of a PSPS, if the need should arise. 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 continues to 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 March 31, 2021 and December 31, 2020, PGE's cumulative deferred costs related to the wildfire response was $22 million and $15 million, respectively. PGE continues to assess the damage to its infrastructure and expects regulatory recovery of prudently incurred restoration costs. 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 deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. Power Costs-Pursuant to the Annual Update Tariff (AUT) process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC, the 2021 AUT included a final increase in power costs for 2021, and a corresponding increase in annual revenue requirement, of $66 million from 2020 levels, which were reflected in customer prices effective January 1, 2021. See "Power Operations" within this Overview section of Item 2 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 March 31, 2021, 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 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 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. 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 8, Contingencies in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements." 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. 39 -------------------------------------------------------------------------------- Table of Contents The Company recorded an estimated refund of $2 million and a collection of $3 million from residential and commercial customers, respectively, for the three months ended March 31, 2021, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. In the first quarter of 2021, the Company continued 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 2021, the 2% limit will be applied to the net prices for the applicable tariff schedules that will be in effect on January 1, 2023. The Company expects to reach its 2021 limit for collection from commercial customers during the third quarter of 2021. No limit 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. As of December 31, 2020, PGE had recorded an estimated net refund of $6 million for 2020, which if approved by the OPUC, will be credited to customers over a one-year period beginning January 1, 2022. 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 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 and $66 million for the year ending December 31, 2021. As of March 31, 2021 and 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 offset the revenue requirement for Boardman. If the OPUC authorizes a refund, PGE would record a regulatory liability with a corresponding charge to earnings.
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 California Independent System Operator's Western Energy Imbalance Market, which allows the Company to, among other things, integrate more renewable energy into the grid by better matching the variable output of renewable resources. PGE also purchases natural gas in the United 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. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues. Wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.
Customers and Demand-The following tables present total energy deliveries and the average number of retail customers by customer type for the periods indicated.
Table of Contents Three Months Ended March 31, % Increase (Decrease) in Energy 2021 Deliveries 2020 Energy deliveries (MWhs in thousands): Retail: Residential 2,239 2,131 5.1 % Commercial 1,564 1,626 (3.8) % Industrial 897 810 10.7 % Subtotal 4,700 4,567 2.9 % Direct access: Commercial 150 170 (11.8) % Industrial 359 355 1.1 % Subtotal 509 525 (3.0) % Total retail energy deliveries 5,209 5,092 2.3 % Wholesale energy deliveries 1,245 1,693 (26.5) % Total energy deliveries 6,454 6,785 (4.9) % Three Months Ended March 31, 2021 2020 Average number of retail customers: Residential 797,602 88 % 787,095 88 % Commercial 110,703 12 110,073 12 Industrial 193 - 194 - Direct access 601 - 627 - Total 909,099 100 % 897,989 100 % Retail energy deliveries for the three months ended March 31, 2021 increased 2.3% compared with the three months ended March 31, 2020, as increases in residential and industrial deliveries more than offset the decline in commercial deliveries. The results for the first quarter of 2020 largely reflected conditions prior to the COVID-19 pandemic. During the pandemic, residential loads have 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. The industrial class as a whole has experienced an increase in energy deliveries, due primarily to continued growth in the high tech and digital services sectors, which saw lesser impacts from noted closures than other sectors. The following table indicates the number of heating and cooling degree-days for the three months ended March 31, 2021 and 2020, along with the current 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport: 41
Table of Contents Heating Degree-days 2021 2020 Avg. January 620 588 719 February 641 605 598 March 544 568 530 Year-to-date 1,805 1,761 1,847
Decrease from the 15-year average (2.3) % (4.7) % After adjusting for the effects of weather, retail energy deliveries for the three months ended March 31, 2021 increased 1.2% compared to the same period of 2020. The increase was driven by an increase of 8% in industrial deliveries and 3% growth in residential energy deliveries partially offset by a decrease in commercial energy deliveries of 5%. Residential average usage per customer saw an increase, which, combined with growth of 1.3% in the average number of residential customers, contributed to increased energy deliveries. The Company's cost-of-service opt-out program caps participation by customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy delivered to Direct Access customers who purchase their energy from Electricity Service Suppliers (ESSs). This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE's total retail energy deliveries for the first three months of 2021. During 2018, the OPUC created a New Large Load Direct Access program for unplanned, large, new loads and large load growth at existing customer sites. In early February 2020, PGE began offering service to customers under this program, which is capped at 119 MWa, based on an order issued by the OPUC in January 2020. With the adoption of the New Large Load Direct Access program in 2020, as much as 18% of the Company's energy deliveries could have been supplied by ESSs. Actual energy deliveries to Direct Access customers by ESSs represented 10% of PGE's total retail energy deliveries for the first three months of 2021 and 2020. 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 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 generating resources for the three months ended March 31, 2021 and 2020:
Table of Contents Actual energy provided Actual energy provided as a compared to projected percentage of total retail Plant availability (1) levels (2) load 2021 2020 2021 2020 2021 2020 Generation: Thermal: Natural gas 94 % 96 % 114 % 101 % 48 % 50 % Coal (3) - 100 103 108 12 24 Wind 94 96 129 164 11 12 Hydro 85 88 81 80 6 8 (1)Plant availability represents the percentage of the period plants were available for operations, which is impacted by planned maintenance and forced, or unplanned, outages. (2)Projected levels of energy are included as part of PGE's AUT. Such projections establish the power cost component of retail prices for the following calendar year. Any shortfall is generally replaced with power from higher cost sources, while any excess generally displaces power from higher cost sources. (3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip availability was 94% during the three months ended March 31, 2021, compared with 92% in 2020. Boardman ceased coal-fired generation on October 15, 2020. Energy received from PGE-owned and jointly-owned thermal plants decreased 18% during the three months ended March 31, 2021 compared to 2020, primarily as a result of Boardman ceasing coal-fired generation on October 15, 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. Total energy received from hydroelectric generation sources, both PGE-owned generation and purchased, decreased 8% during the three months ended March 31, 2021 compared to 2020. Energy received from mid-Columbia hydroelectric projects decreased 1% in the three months ended March 31, 2021, and the energy generated by the Company-owned facilities decreased 14%, due to less favorable hydro conditions in 2021. Energy expected to be received from hydroelectric resources is projected annually in the AUT based on a modified hydro study, which utilizes 80 years of historical stream flow data. See "Purchased power and fuel" in the Results of Operations section in this Item 2, for further detail on regional hydro results. Energy received from PGE-owned wind resources and under contracts increased 19% during the three months ended March 31, 2021 compared to 2020 primarily due to the addition of Wheatridge. Energy expected to be received from wind generating resources is projected annually in the AUT based on historical generation. Wind generation forecasts are developed using a 5-year rolling average of historical wind levels or forecast studies when historical data is not available. As a result of the generation increase in comparison to projected levels, more PTCs were produced in 2021 than 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 43 -------------------------------------------------------------------------------- Table of Contents extent that it results in PGE's actual regulated return on equity (ROE) for the given year being no less than 1% above the Company's latest authorized ROE, while a collection will occur only to the extent that it results in PGE's actual regulated ROE for that year being no greater than 1% below the Company's authorized ROE. The following is a summary of the results of the Company's PCAM as calculated for regulatory purposes for the three months ended March 31, 2021 and 2020, respectively: •For the three months ended March 31, 2021, actual NVPC was $13 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be below the baseline, and outside the established deadband range. PGE does not expect its actual regulated ROE to exceed 10.5%; accordingly, no estimated refund to customers is expected under the PCAM for 2021. •For the three months ended March 31, 2020, actual NVPC was $20 million below baseline NVPC. For the year ended December 31, 2020, actual NVPC, excluding certain trading losses totaling $127 million, was $13 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated collection to customers was recorded pursuant to the PCAM for 2020.
Critical Accounting Policies
The Company's critical accounting policies are outlined in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 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, amortization, and other operation and maintenance expenses. The presentation of Gross margin is intended to supplement an understanding of PGE's operating performance in 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. 44 -------------------------------------------------------------------------------- Table of Contents The results of operations are as follows for the periods presented (dollars in millions):
Three Months Ended March 31,
2021 % Increase (Decrease) 2020 Total revenues $ 609 $ 573 6 % Purchased power and fuel 169 153 10 % Gross margin(1) 440 420 5 % Other operating expenses: Generation, transmission and distribution 80 73 10 % Administrative and other 86 71 21 % Depreciation and amortization 103 108 (5) % Taxes other than income taxes 38 35 9 % Total other operating expenses 307 287 7 % Income from operations 133 133 - % Interest expense, net(2) 34 33 3 % Other income: Allowance for equity funds used during construction 4 3 33 % Miscellaneous income, net 2 (4) 150 % Other income, net 6 (1) 700 % Income before income tax expense 105 99 6 % Income tax expense 9 18 (50) % Net income $ 96 $ 81 19 %
(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE's Condensed Consolidated Statements of Income. (2) Includes an allowance for borrowed funds used during construction of $2 million for the three months ended March 31, 2021 and 2020.
45 -------------------------------------------------------------------------------- Table of Contents Three Months Ended March 31, 2021 compared with the three months ended March 31, 2020 Net income - The following items contributed to the change in Net income for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions): Three Months Ended March 31, 2020 $ 81 Income tax expense 9
Other operating revenues primarily from the resale of excess natural gas used for fuel in 2021 that did not occur in 2020
7 Revenue from Wheatridge placed in service 4 Gains from Nonqualified benefit trust 4 Depreciation and amortization expense 3 Retail energy deliveries 2 Purchased power and fuel expense (2) Wholesale revenues (12) March 31, 2021 $ 96 Change in Net income $ 15 46
Table of Contents
Total revenues consist of the following for the periods presented (dollars in millions): Three Months Ended March 31, 2021 2020 Retail (1): Residential $ 310 51 % $ 279 48 % Commercial 162 26 159 28 Industrial 60 10 51 9 Direct Access 11 2 11 2 Subtotal 543 89 500 87 Alternative revenue programs, net of amortization (3) - 9 2 Other accrued revenues, net (2) 13 2 5 1 Total retail revenues 553 91 514 90 Wholesale revenues 33 5 47 8 Other operating revenues 23 4 12 2 Total revenues $ 609 100 % $ 573 100 % (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 $4 million for both 2021 and for 2020. Industrial revenues from ESS customers were $7 million for both 2021 and 2020. (2) Amount for 2020 is primarily comprised of $6 million in amortization, including interest, related to the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA). For 2021, $11 million resulted from use of the storm cost deferral to partially offset expenses related to the January and February storms. Total retail revenues - The following items contributed to the increase in Total retail revenues for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions): Three Months Ended March 31, 2020 $ 514
Increase as a result of the AUT, approved by the OPUC, with an expected offset in Purchased power and fuel
17 Recovery in Revenues of Storm related expenses in 2021 12
Increase from higher retail energy deliveries driven by the impact of COVID-19 on residential customers in the first quarter 2021 and higher industrial demand
Increase resulting from the combination of various supplemental tariffs and adjustments, the largest of which pertains to Wheatridge being placed into service
Increase as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19
Decrease attributed to alternative revenue programs related to the decoupling mechanism due to increased residential use per customer
(12) March 31, 2021 $ 553 Change in Total retail revenues $ 39 47
-------------------------------------------------------------------------------- Table of Contents Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company's efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. For the three months ended March 31, 2021 wholesale revenues decreased $14 million, or 30%, from the three months ended March 31, 2020, as a result of a $13 million decrease related to 27% lower wholesale sales volume and a $1 million decrease as a result of a 3% decline in average wholesale sales prices. The reduction in volume resulted from a combination of reduced quarter over quarter thermal generation with the retirement of Boardman, reduced hydro generation, and a 2% increase in retail load requirement. Other operating revenues for the three months ended March 31, 2021 increased $11 million from the three months ended March 31, 2020 due primarily to market conditions and economic dispatch that provided $10 million more revenue from the resale of natural gas in excess of amounts needed for the Company's generation portfolio back into the wholesale market. Natural gas prices were significantly higher in 2021 after being depressed in 2020 due to milder than average winter temperatures in North America in 2020 that resulted in an oversupply of natural gas and lower prices. 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 three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions, except for average variable power cost per MWh): Three Months Ended March 31, 2020 $ 153 Increase related to average variable power cost per MWh 13 Increase related to total system load 3 March 31, 2021 $ 169 Change in Purchased power and fuel $ 16 Average variable power cost per MWh: March 31, 2020 $ 23.31 March 31, 2021 $ 27.14 Total system load (MWhs in thousands): March 31, 2020 6,586 March 31, 2021 6,237 For the three months ended March 31, 2021, the $13 million increase related to the change in average variable power cost per MWh (which includes PGE-generated power and market purchases), was driven by a 19% increase on the average cost of purchased power, offset with a 8% decrease on the average cost for the Company's own generation. The $3 million increase related to total system load was primarily due to a 20% increase in purchased power (which was purchased at higher average prices), offset by a 17% decrease in the Company's own generation, driven largely by the retirement of Boardman and lower hydro and wind production. 48 -------------------------------------------------------------------------------- Table of Contents PGE's sources of energy, total system load, and retail load requirement for the periods presented are as follows:
Three Months Ended March 31,
2021 2020 Sources of energy (MWhs in thousands): Generation: Thermal: Natural gas 2,383 38 % 2,433 37 % Coal 582 9 1,186 18 Total thermal 2,965 47 3,619 55 Hydro 317 5 369 6 Wind 532 9 585 9 Total generation 3,814 61 4,573 70 Purchased power: Term 1,844 30 1,604 24 Hydro 340 5 345 5 Wind 239 4 64 1 Total purchased power 2,423 39 2,013 30 Total system load 6,237 100 % 6,586 100 % Less: wholesale sales (1,245) (1,693) Retail load requirement 4,992 4,893
The following table presents the forecasted April-to-September 2021 and the actual 2020 runoff at particular points of major rivers relevant to PGE's hydro resources:
Runoff as a Percent of Normal*
Location 2021 Forecast 2020 Actual Columbia River at The Dalles, Oregon 89 % 104 % Mid-Columbia River at Grand Coulee, Washington 94 109 Clackamas River at Estacada, Oregon 85 75 Deschutes River at Moody, Oregon 90 86
* Volumetric water supply forecasts and historical averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center, with the Natural Resources Conservation Service and other cooperating agencies.
Actual NVPC, the following items contributed to the increase in Actual NVPC for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions): Three Months Ended March 31, 2020 $ 106 Increase in Purchased power and fuel expense 16 Decrease (Increase) in Wholesale revenues 14 March 31, 2021 $ 136 Change in NVPC $ 30 For further information regarding NVPC in relation to the PCAM, see "Purchased power and fuel expense" and "Revenues" within this "Results of Operations" for more details. 49 -------------------------------------------------------------------------------- Table of Contents For the three months ended March 31, 2021 and 2020, actual NVPC was $13 million below and $20 million above baseline NVPC, respectively. Based on forecast data, NVPC for the year ending December 31, 2021 is currently estimated to be below the baseline and outside the deadband. PGE does not expect its actual regulated ROE to exceed 10.5%, accordingly, no estimated refund to customers is expected under the PCAM for 2021. Generation, transmission and distribution - The following items contributed to the increase in Generation, transmission and distribution for the three months ended March 31, 2021 compared to the same period in 2020 (dollars in millions): Three Months Ended March 31, 2020 $ 73
January and February storm costs recovered via the Company's storm cost
12 recovery mechanism Decrease primarily due to lower maintenance expense and lower general (6)
maintenance costs at some of the Company's generation facilities Miscellaneous expenses
1 March 31, 2021 $ 80 Change in Generation, transmission and distribution $ 7 In the first quarter of 2021, PGE deferred $41 million of incremental costs related to February ice storm damage in PGE's service territory. See "February 2021 Ice Storm" within "Perform as a Business" under the "Overview" section of this Item 2. for more information. Administrative and other - The following items contributed to the increase in Administrative and other for the three months ended March 31, 2021 compared to the same period in 2020 as follows (dollars in millions): Three
March 31, 2020 $ 71 Higher legal and other professional service expenses 5 Higher employee wage and benefits expenses 4 Increase to bad debt expense 3 Miscellaneous expenses 3 March 31, 2021 $ 86 Change in Administrative and other $ 15 Depreciation and amortization expense decreased $5 million in the three months ended March 31, 2021 compared to the same period in 2020, largely as a result of asset retirements, which were partially offset by capital additions.
Taxes other than income taxes expense increased $3 million in 2021 compared with 2020, primarily due to higher Oregon property taxes.
Interest expense, net increased $1 million in the three months ended March 31, 2021 compared to the same period in 2020. The increase was primarily attributable to the higher average balance of outstanding debt, including short-term debt.
50 -------------------------------------------------------------------------------- Table of Contents Other income, net increased $7 million for the three months ended March 31, 2021 compared to the same period in 2020. The increase was primarily due to market changes on the non-qualified benefit trust. Income tax expense decreased $9 million for three months ended March 31, 2021, compared to the same period in 2020, with the decreases primarily due to a cumulative catch-up adjustment to defer and recognize a regulatory asset for previously recorded deferred income tax expenses on a certain local flow-through tax. See Note 10, Income Taxes in the Notes to Condensed Consolidated Financial Statements in Item 1.-"Financial Statements," for more information.
LIQUIDITY AND CAPITAL RESOURCES
PGE's access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company's current operating activities, including the purchase of power and fuel. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, repairs from major storm damage, information technology systems, and debt refinancing activities. PGE's liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposit requirements related to wholesale market activities, which can vary depending upon the Company's forward positions and the corresponding price curves. The following summarizes PGE's cash flows for the periods presented (dollars in millions): Three Months Ended March 31, 2021 2020 Cash and cash equivalents, beginning of period $ 257 $ 30 Net cash provided by (used in): Operating activities 168 155 Investing activities (162) (157) Financing activities (128) 2 Increase (decrease) in cash and cash equivalents (122) - Cash and cash equivalents, end of period $
135 $ 30
Cash Flows from Operating Activities-Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. The following items contributed to the net change in cash flows from operations for the three months ended March 31, 2021 compared with the three months ended March 31, 2020 (dollars in millions): 51
Table of Contents Increase/ (Decrease) Net income $ 15 Deferral of incremental storm costs (41) Accounts payable and accrued liabilities 48 Accounts receivable, net (21) Margin deposits 18 Decoupling 12 Deferred income tax (8) Depreciation and amortization (5) Other (5) Net change in cash flow from operations $ 13 PGE estimates that non-cash charges for depreciation and amortization in 2021 will range from $410 million to $430 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $600 million to $650 million. For additional information, see "Contractual Obligations" in this Liquidity and Capital Resources section of Item 2. 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. Net cash used in investing activities for the three months ended March 31, 2021 increased $5 million when compared with the three months ended March 31, 2020, as capital expenditures related to the IOC and winter storm restoration increased. Excluding AFDC, the Company plans to make capital expenditures of $700 million in 2021, which it expects to fund with cash to be generated from operations during 2021, as discussed above, and the issuance of short- and long-term debt securities. For additional information, see "Debt and Equity Financings" in this Liquidity and Capital Resources section of Item 2. Cash Flows from Financing Activities-Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the three months ended March 31, 2021, net cash provided by financing activities was primarily the result of proceeds from the combination of a $140 million payment on long-term debt, the issuance of a new 364-day term loan of $200 million, repayment of prior 364-day term loan of $150 million, and payment of $36 million of dividends. Capital Requirements
The following table presents PGE's estimated capital expenditures and contractual maturities of long-term debt for 2021 through 2025 (dollars in millions, excluding AFDC).
2021 2022 2023 2024 2025 Ongoing capital expenditures* $ 600 $ 550 $ 550 $ 550 $ 550 Integrated Operations Center 100 - - - - Total capital expenditures $ 700 $ 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 connections. Includes preliminary engineering and removal costs.
Debt and Equity Financings
Table of Contents
PGE's ability to secure sufficient short- and long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors, such as the volatility in the capital markets in response to COVID-19. Management believes that the availability of its revolving credit facility, the expected ability to issue short- and long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company's anticipated capital and operating requirements for the foreseeable future. For 2021, PGE expects to fund estimated capital requirements with cash from operations, which is expected to range from $600 million to $650 million, issuances of long-term debt securities of up to $350 million, and the issuance of short-term debt or commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures and debt payments. Short-term Debt. Pursuant to an order issued by the Federal Energy Regulatory Commission 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 March 31, 2021 (in millions): As of March 31, 2021 Capacity Outstanding Available Revolving credit facility (1) $ 500 $ - $ 500 Letters of credit (2) 220 75 145 Total credit $ 720 $ 75 $ 645 Cash and cash equivalents 135 Total liquidity $ 780 (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 March 31, 2021, PGE had a $500 million unsecured 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 to provide cash 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 remaining term of the applicable credit facility. The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the revolving credit facility. As of March 31, 2021, PGE had no commercial paper outstanding. The aggregate unused available credit capacity under the revolving credit facility was $500 million. The Company has elected to limit its borrowings under the revolving credit facility in order to allow coverage for the potential need to repay any commercial paper that may be outstanding at the time. On March 31, 2021, PGE obtained an unsecured 364-day term loan in the aggregate principal amount of $200 million. The term loan will bear interest for the relevant interest period at LIBOR plus 0.70%, with the interest rate subject to adjustment pursuant to the terms of the loan. The credit agreement expires on March 30, 2022, with any outstanding balance due and payable on such date. The Company used a portion of the proceeds to repay the prior 364-day $150 million term loan that was issued on April 9, 2020, with the remainder of the proceeds used for general corporate purposes. 53 -------------------------------------------------------------------------------- Table of Contents Long-term Debt. As of March 31, 2021, total long-term debt outstanding, net of $12 million of unamortized debt expense, was $2,906 million. On January 6, 2021, the Company made a $140 million scheduled repayment on a 2.51% Series of FMBs with available cash. Capital Structure. PGE's financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities and excluding lease obligations) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and provides access to long-term capital at favorable interest rates. The Company's common equity ratio was 46.3% and 45.0% as of March 31, 2021 and December 31, 2020, respectively.
Credit Ratings and Debt Covenants
PGE's secured and unsecured debt is rated investment grade by Moody's Investors Service (Moody's) and S&P Global Ratings (S&P), with current credit ratings and outlook as follows: Moody's S&P First Mortgage Bonds A1 A Senior unsecured debt A3 BBB+ Commercial paper P-2 A-2 Outlook Stable Stable In the event Moody's or S&P reduce their credit rating on PGE's unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits that PGE provides as collateral are classified as Margin deposits, which is included in Other current assets on the Company's condensed consolidated balance sheets, while any letters of credit issued are not reflected on the condensed consolidated balance sheets. As of March 31, 2021, PGE had posted $19 million of collateral with these counterparties, consisting of $9 million in cash and $10 million in letters of credit. Based on the Company's energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2021, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $33 million, and decreases to $7 million by December 31, 2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $119 million and decreases to $84 million by December 31, 2021 and to $77 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 Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2021, under the most restrictive issuance test in the Indenture, the Company could have issued up to $683 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property. 54 -------------------------------------------------------------------------------- Table of Contents 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 March 31, 2021, the Company's debt-to-total capital ratio, as calculated under the credit agreement, was 55.2%.
Off-Balance Sheet Arrangements
PGE has no off-balance sheet arrangements, other than surety bonds and outstanding letters of credit, 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. PGE's surety bond and letter of credit arrangements are described in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021, there have been no material changes outside the ordinary course of business as of March 31, 2021.
PGE's contractual obligations for 2021 and beyond are set forth in Part II, Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 19, 2021. For such obligations, there have been no material changes outside the ordinary course of business as of March 31, 2021.