Portland General Electric Company

POR

US7365088472

Electric Utilities

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Apr. 22	Portland General Electric Raises Quarterly Dividend 5.3% to $0.50 Per Share, Payable Around July 15 to Shareholders on June 24	MT
Apr. 20	Portland General Electric Company Declares Quarterly Dividend, Payable on or Before July 15, 2024	CI

PORTLAND GENERAL ELECTRIC CO /OR/ Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-Q)

April 28, 2022 at 06:15 am EDT

Forward-Looking Statements



The information in this report includes statements that are forward-looking
within the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements include, but are not limited to, statements that
relate to expectations, beliefs, plans, assumptions, and objectives concerning
future results of operations, business prospects, loads, outcome of litigation
and regulatory proceedings, capital expenditures, market conditions, future
events or performance, and other matters. Words or phrases such as
"anticipates," "believes," "estimates," "expects," "intends," "plans,"
"predicts," "projects," "will likely result," "will continue," "should," or
similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed. PGE's expectations, beliefs and projections are
expressed in good faith and are believed by the Company to have a reasonable
basis including, but not limited to, management's examination of historical
operating trends and data contained either in internal records or available from
third parties, but there can be no assurance that PGE's expectations, beliefs,
or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in such forward-looking statements include:



•governmental policies, legislative action, and regulatory audits,
investigations, and actions, including those of the Federal Regulatory Energy
Commission (FERC) and the Public Utility Commission of Oregon, (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, operating expenses, deferrals, timely recovery of
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;

•inflation and interest rates;



•changing customer expectations and choices that may reduce customer demand for
its services may impact PGE's ability to make and recover its investments
through rates and earn its authorized return on equity, including the impact of
growing distributed and renewable generation resources, changing customer demand
for enhanced electric services, and an increasing risk that customers procure
electricity from registered Electricity Service Suppliers (ESSs) or community
choice aggregators;

•the outcome of legal and regulatory proceedings and issues including, but not
limited to, the matters described under the heading of Regulatory Matters in the
Overview section of this Item 2, and Note 8, Contingencies in the Notes to the
Condensed Consolidated Financial Statements of this Quarterly Report on Form
10-Q;

•natural or human-caused disasters and other risks, including, but not limited
to, earthquake, flood, ice, drought, extreme heat, lightning, wind, fire,
accidents, equipment failure, acts of terrorism, computer system outages and
other events that disrupt PGE operations, damage PGE facilities and systems,
cause the release of harmful materials, cause fires, and subject the Company to
liability;

•unseasonable or extreme weather and other natural phenomena, such as the
greater size and prevalence of wildfires in Oregon in recent years, which could
affect public safety, customers' demand for power and PGE's ability and cost to
procure adequate power and fuel supplies to serve its customers, PGE's ability
to access the wholesale energy market, PGE's ability to operate its generating
facilities and transmission and

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distribution systems, the Company's costs to maintain, repair, and replace such
facilities and systems, and recovery of costs;

•PGE's ability to effectively implement a public safety power shutoff (PSPS) and
de-energize its system in the event of heightened wildfire risk, which could
cause damage to the Company's own facilities or lead to potential liability if
energized systems are involved in wildfires that cause harm;

•operational factors affecting PGE's power generating facilities and battery
storage facilities, including forced outages, unscheduled delays, hydro and wind
conditions, and disruption of fuel supply, any of which may cause the Company to
incur repair costs or purchase replacement power at increased costs;

•default or nonperformance on the part of any parties from whom PGE purchases capacity or energy, which may cause the Company to incur costs to purchase replacement power and related renewable attributes at increased costs;



•complications arising from PGE's jointly-owned plant, including changes in
ownership, adverse regulatory outcomes or legislative actions, or operational
failures that result in legal or environmental liabilities or unanticipated
costs related to replacement power or repair costs;

•delays in the supply chain and increased supply costs, failure to complete
capital projects on schedule or within budget, failure of counterparties to
perform under agreements, or the abandonment of capital projects, any of which
could result in the Company's inability to recover project costs;

•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, whether global or local in nature, including
unseasonable or extreme weather and other natural phenomena that may affect
energy costs or consumption, increase the Company's costs, cause damage to PGE
facilities and system, or adversely affect its operations;

•changes in residential, commercial, or industrial customer demand, or demographic patterns, in PGE's service territory;

•the effectiveness of PGE's risk management policies and procedures;

•cybersecurity attacks, data security breaches, physical security breaches, or other malicious acts that cause damage to the Company's generation, transmission, or distribution facilities, information technology systems, inhibit the capability of equipment or systems to function as designed or expected, or result in the release of confidential customer, employee, or Company information;



•employee workforce factors, including potential strikes, work stoppages,
transitions in senior management, the ability to recruit and retain key
employees and other talent, and turnover due to macroeconomic trends such as
voluntary resignation of large numbers of employees similar to that experienced
by other employers and industries since the beginning of the coronavirus
(COVID-19) pandemic;

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•new federal, state, and local laws that could have adverse effects on operating
results;

•failure to achieve the Company's greenhouse gas emission goals or being
perceived to have either failed to act responsibly with respect to the
environment or effectively responded to legislative requirements concerning
greenhouse gas emission reductions, any of which can lead to adverse publicity
and have adverse effects on the Company's operations and/or damage the Company's
reputation;

•political and economic conditions;



•the impact of widespread health developments, including the global COVID-19
pandemic, and responses to such developments (such as voluntary and mandatory
quarantines, including government stay at home orders, as well as shut downs and
other restrictions on travel, commercial, social and other activities), which
could materially and adversely affect, among other things, demand for electric
services, customers' ability to pay, supply chains, personnel, contract
counterparties, liquidity and financial markets;

•changes in financial or regulatory accounting principles or policies imposed by governing bodies;

•acts of war or terrorism; and

•risks and uncertainties related to RFP final shortlist projects, including, but not limited to regulatory processes, inflationary impacts, supply chain constraints, supply cost increases (including application tariffs impacting solar module imports), and legislative uncertainty.




Any forward-looking statement speaks only as of the date on which such statement
is made and, except as required by law, PGE undertakes no obligation to update
any forward-looking statement to reflect events or circumstances after the date
on which such statement is made or to reflect the occurrence of unanticipated
events. New factors emerge from time to time and it is not possible for
management to predict all such factors or assess the impact of any such factor
on the business or the extent to which any factor, or combination of factors,
may cause results to differ materially from those contained in any
forward-looking statement.

OVERVIEW



Management's Discussion and Analysis of Financial Condition and Results of
Operations (MD&A) is intended to provide an understanding of the business
environment, results of operations, and financial condition of PGE. 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. PGE is committed to
developing products and service offerings for the benefit of retail and
wholesale customers. The Company generates revenues and cash flows primarily
from the sale and distribution of electricity to retail customers in its service
territory.

Company Strategy

The Company exists to power the advancement of society. PGE energizes lives,
strengthens communities, and fosters energy solutions that promote social,
economic, and environmental progress. The Company is committed to being a clean
energy leader and delivering steady growth and returns to shareholders. PGE is
focused on working with customers, communities, policy makers, and other
stakeholders to deliver affordable, safe, reliable electricity service to all,
while increasing opportunities to deliver clean and renewable energy, reducing
greenhouse gas emissions, and responding to evolving customer expectations. At
the same time, the Company is building an increasingly smart, integrated, and
interconnected grid that spans from residential customers to other utilities
within the region. PGE is transforming all aspects of its business to empower
its workforce to be even more results oriented to serve customers well. To
create a clean energy future, PGE is focused on the following strategic
initiatives:

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•Decarbonize the power supply by reducing GHG emissions associated with the
power served to customers by at least 80% by 2030, 90% by 2035, and achieving
zero GHG emissions associated with the power served to customers by 2040;

•Electrify other sectors of the economy like transportation and buildings that are also transforming to reduce GHG emissions; and

•Perform by improving work efficiency, safety of its workforce, and reliability of its systems and equipment, all while adhering to the Company's long-term earnings per diluted share growth guidance of 4-6% on average.

Climate change



State-mandated GHG reduction targets-In June 2021, the Oregon legislature passed
HB 2021, establishing a 100% clean electricity by 2040 framework for PGE and
other investor-owned utilities and electric service suppliers in the state. A
number of provisions in the bill align with PGE's strategic direction, and
highlight Oregon's ambitious, economy-wide goals to combat climate change. The
GHG reduction targets applicable to these regulated entities are an 80%
reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year
thereafter. For more information regarding HB 2021 and the baseline to which the
target reductions apply, see the "Environmental Laws and Regulations" section
within this Overview.

Empowering customers and communities-PGE's customers are committed to purchasing
clean energy, as over 235 thousand residential and small commercial customers
voluntarily participate in PGE's Green Future Program, the largest renewable
power program by participation in the nation. In 2017, Oregon's most populous
city, Portland, and most populous county, Multnomah, each passed resolutions to
achieve 100 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.

The Company implemented a customer service option, the Green Future Impact (GFI)
Program, which is a renewable energy program that allows customers to have a
choice in how they source their electricity. Under the GFI Program, customers
can enroll in a Customer-Supplied Option (CSO) or PGE-Supplied Option. Under the
CSO, participants are responsible for finding a renewable energy facility that
meets established requirements and bringing those resources to PGE. Under the
PGE-Supplied option, customers who enrolled in Phase I can receive energy from
PGE-provided purchased power agreements (PPAs) for renewable resources and
customers who enroll in Phase II can receive energy from PGE-provided PPAs for
renewable resources or energy from renewable resources that are PGE owned, under
certain conditions.

As of March 31, 2022, the GFI Program has an approved capacity of 750 MW. Through this voluntary program, the Company seeks to support the customers' clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power.



Extreme weather-In recent years, PGE's territory has experienced unprecedented
heat, historic ice and snowstorms, and wildfires. In June 2021, temperatures in
the region reached all-time recorded highs, shattering the Company's previous
peak load demand, and surpassing the prior summer peak load by nearly 12%. In
February 2021, PGE's service territory experienced an ice storm, which led to
historic levels of customer power outages, and caused considerable expense for
service restoration and damage repair (see "February 2021 Ice Storms and Damage"
in the "Regulatory Matters" section of this Overview for more information on the
impact to PGE's results of operation). In 2020, Oregon experienced one of the
most destructive wildfire seasons on record, with over one million acres of land
burned (see "Wildfire" in the "Regulatory Matters" section of this Overview for
more information on the impact to PGE's results of operation). The increase and
severity of extreme weather events highlights the importance of combating the
effects of climate change through decarbonizing the power supply and investing
in a more reliable and resilient grid.


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Investing in a clean energy future

Building a resilient grid-Recent extreme weather events driven by changes to
global systems affecting rainfall patterns and seasonal snow cover in the region
have impacted PGE's customers significantly, and the frequency and severity of
these events are accelerating. PGE's grid of the future is increasingly smart
and adaptive, so that the electric service its customers depend on remains
reliable even under uncertain and extreme conditions. For example, the Company
uses wireless smart sensors and centrally controlled automated switches to help
isolate disruptions and more quickly reroute power, preventing or shortening
disruptions. In the field, PGE uses advanced data analytics to optimize system
investments and maintenance. The Company is updating its design standards, so
that smart sensors and switches are constructed to withstand more extreme
weather, particularly in high-risk wildfire areas.

The Resource Planning Process-PGE's resource planning process includes working
with customers, stakeholders, and regulators to chart the course toward a clean,
affordable, and reliable energy future. With the passage of House Bill 2021, PGE
will prepare a Clean Energy Plan (CEP) which will articulate the Company's
strategy to meet the 2030 and 2040 decarbonization targets. The first CEP is
anticipated to be filed in the Spring of 2023 and will set annual
decarbonization targets and articulate how PGE will achieve an equitable
transition to a decarbonized grid. PGE's resource planning analysis and
stakeholder engagement will continue to occur through the Integrated Resource
Plan (IRP) and Distribution System Plan (DSP) processes.

PGE's 2016 IRP process resulted in the development of the following renewable resources:



•Wheatridge Renewable Energy Facility (Wheatridge)-In 2018, the Company issued a
request for proposals (RFP) seeking to procure approximately 100 average
megawatts (MWa) of qualifying renewable resources. The prevailing project 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 in-service in 2020.
Subsidiaries of NextEra Energy Resources, LLC operate the facility and own the
balance of the wind resource, along with the solar and battery components, which
were placed in-service in March of 2022, and sell their portion of the output to
PGE.

In May 2020, PGE obtained an OPUC order acknowledging the Company's 2019 IRP and
associated Action Plan for PGE to acquire resources over the next four years, an
important step in acquiring the necessary clean and renewable and capacity
resources by 2030. In October 2021, PGE initiated its 2021 All-Source RFP public
process, seeking approximately 1,000 MW of renewable and non-emitting resources.
PGE estimates that the 2021 All-Source RFP will meet a portion of the Company's
projected need of approximately 1,500 to 2,000 MW of clean and renewable
resources and approximately 800 MW of non-emitting dispatchable capacity
resources in order to meet the Company's 2030 emissions reduction target. PGE
also expects it will need to exit Colstrip and is actively working on plans to
achieve this by the end of 2025.

The All-Source RFP seeks:

•Approximately 375 to 500 MW of renewable resources;

•Approximately 375 MW of non-emitting dispatchable capacity resources that can be used to meet peak customer demand; and



•One or more resources for the Company's Green Future Impact (GFI) Program.
Under the GFI Program, PGE plans to acquire up to 100 MW of a new wind, solar,
or hybrid renewable and battery storage resources to meet subscriber demand
under the PGE supply option. The Company does not expect GFI Program resources
considered in the 2021 All-Source RFP to contribute towards the 150 MWa
renewable energy target envisioned under the 2019 IRP Action Plan.

PGE will work with the OPUC to evaluate whether procuring resources beyond the
amounts identified above are in the best interest of customers given the
significant new clean resources additions necessary to meet HB 2021 requirements
in 2030.

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Renewable resources in PGE's 2021 All-Source RFP must be eligible under Oregon's
Renewable Portfolio Standard (RPS) and qualify for the federal production tax
credit (PTC) or the federal investment tax credit. All resources (dispatchable
capacity or renewable) must be online by the end of 2024, with certain
exceptions for long-lead time resources.

PGE issued the final RFP after receiving approval with modifications from the
OPUC in December 2021, and proposals were submitted in January 2022. Bids were
evaluated based on the OPUC-approved scoring methodology. Following
determination of a final shortlist, PGE plans to submit a request for
acknowledgement of the shortlist to the OPUC on May 5, 2022 that includes seven
distinct projects submitted by five bidders for renewable resources and six
distinct projects by four bidders for capacity resources.

The proposals for renewable resources provide various combinations of wind,
solar, and battery storage options that include power purchase agreements (PPA)
along with Company-owned resources. The proposals for non-emitting capacity
resources provide battery storage and pumped storage options that include PPAs
along with Company-owned resources. The ultimate outcome of the RFP process may
involve the selection of multiple projects for both renewable and capacity
resources.

PGE will request that the OPUC acknowledge the RFP shortlist by July 15, 2022 to
enable the Company to execute definitive agreements. RFP final shortlist
projects were evaluated and selected based on conditions as of the shortlist
date. PGE intends to commence negotiations with one or more bidders and finalize
negotiations prior to the end of 2022 to allow sufficient time to capture
expiring federal tax credits for the benefit of customers.

In February 2022, NewSun Energy LLC ("NewSun") filed a petition for judicial
review in the Marion County Circuit Court against the OPUC challenging the
scoring methodology in the RFP. PGE has joined in the case as an intervenor.
NewSun also filed a motion to stay the RFP process, which the Court subsequently
denied. The OPUC has filed a motion to dismiss the case and PGE has joined the
OPUC's motion to dismiss. NewSun opposes the motion. PGE cannot predict the
outcome of the proceeding or potential impact, if any, to its ongoing RFP
process.

In October 2021, PGE filed its inaugural Distribution System Plan (DSP), which
lays out plans to build a grid that empowers customers to make energy management
choices to support decarbonization and supports a two-way energy ecosystem with
resources like batteries, EV charging, and solar panels where
communities-especially underserved Oregonians-need them. The plan consists of
two parts, the first of which was acknowledged by the OPUC on March 8, 2022.
Part Two is expected to be filed in August of 2022.

In October 2021, PGE filed an extension waiver for the next IRP that the OPUC approved. As a result, the next IRP will be filed for OPUC consideration by March 31, 2023.



Electrify the economy-To help Oregon reach its decarbonization goals, PGE is
working to build a safe, reliable, and affordable, economy-wide, clean energy
future. The Company is committed to increase electrification of buildings and
support the accelerating pace of vehicle electrification.

Transportation electrification is one of the most significant ways to reduce GHG
emissions in Oregon. PGE is engaged with customers and communities to develop
infrastructure projects aimed at improving accessibility to electric vehicle
charging stations, build fleet partnerships, and offer programs to encourage
customers to advance transportation electrification.

In 2019, PGE filed with the OPUC its first Transportation Electrification plan,
which considers current and planned activities, along with both existing and
potential system impacts, in relation to the State's carbon reduction goals. In
2020, the OPUC approved the plan and related costs and revenues associated with
the Transportation Electrification and Electric Vehicle Charging pilot programs.
In 2021, the Oregon legislature enacted House Bill 2165, ensuring the OPUC has
clear and broad authority to allow electric company investments in
infrastructure to support transportation electrification.
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Businesses and families continue to turn to electricity to serve their home and
workplace needs and PGE continues to share information on the benefits of
electric appliances, landscaping tools and equipment, and heat pumps, which
provide efficient heating and cooling. In addition, the Company continues to
pursue advanced technologies to enhance the grid, pursue distributed generation
and energy storage, and develop microgrids and the use of data and analytics to
better predict demand and support energy-saving customer programs.

Environmental Laws and Regulations



House Bill 2021-In June 2021, the Oregon Legislature passed HB 2021, which
requires retail electricity providers to reduce GHG emissions associated with
serving Oregon retail electricity consumers, compared to their baseline
emissions levels by 80% by 2030, 90% by 2035, and 100% by 2040. The baseline
emissions levels for the investor-owned utilities are the average annual GHG
emissions for the years 2010, 2011, and 2012 associated with the electricity
sold to their retail electricity consumers as reported to the Oregon Department
of Environmental Quality (ODEQ).

Utilities must develop a clean energy plan (CEP) for meeting the targets
concurrent with the development of each IRP. In reviewing the CEP, the OPUC must
ensure that utilities demonstrate continual progress and are taking actions as
soon as practicable that facilitate rapid reduction of GHG emissions and the
transition to an equitable grid at reasonable costs to retail electricity
consumers. The OPUC is also given authority to apply a performance incentive for
early compliance with one or more of the clean energy targets.

Regulated entities will continue to report annual GHG emissions to ODEQ, as they
do today. In compliance years, which are 2030, 2035, and 2040 and every year
thereafter, the OPUC will use the data reported to ODEQ for that compliance year
to determine whether the reduction targets are met. In determining compliance,
if the utility has emissions in excess of the target, the OPUC must take into
consideration unplanned emissions necessary to meet load if the utility
experienced unexpected challenges, such as transmission constraints or
under-production from hydro and other renewable resources. The bill also
includes certain compliance exceptions to protect customers, including a cost
cap and the ability for the OPUC to grant a temporary exemption if a utility is
unable to comply with mandatory reliability standards.

The legislation also:

•Aligns with PGE decarbonization goals while protecting affordability and reliability;

•Establishes clear decarbonization authority for the OPUC, including authority over ESSs;

•Modernizes competition provisions of Oregon's electricity restructuring law from 1999, Oregon Senate Bill 1149 (SB 1149),



•Provides clear authority and process for a community-wide green tariff program
for customers 30 kilowatts and smaller and allows utilities the ability to earn
a return on investments in program resources, and

•Codifies non-bypassability of costs to ensure all customers pay their share of HB 2021 policy costs.

Governor Executive Orders-In 2020, the Governor of Oregon issued an executive order directing state agencies to seek to reduce and regulate GHG emissions.

Among other things, the executive order:

•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-

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•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 emissions 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 ODEQ 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. The ODEQ adopted such a program, referred to as the Climate Protection Plan, in December 2021; and

•Strengthened the reduction goals of the state's Clean Fuels Program and extended the program, from the previous rule that required a ten percent reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25 percent reduction below 2015 levels by 2035.



RPS Standards and Other Laws-In 2016, Oregon Senate Bill 1547 (SB 1547) set a
benchmark for how much electricity must come from renewable sources 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).

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 Colstrip from 2042 to 2030. In 2020, the owners
of Colstrip Units 1 and 2 permanently retired those two units. Although PGE has
no direct ownership interest in those two units, the Company does have a 20%
ownership share in Colstrip Units 3 and 4, which utilize certain common
facilities with Units 1 and 2.

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 December 2021, the OPUC approved
PGE's depreciation study (OPUC Docket UM 2152), which will accelerate
depreciation on Colstrip through December 31, 2025. Depreciation rates will
change and customer collection would coincide with the price effective date of
the Company's 2022 General Rate Case (2022 GRC). For further information on the
2022 GRC, see "General Rate Case" in the "Regulatory Matters" section of this
Overview. The Company continues to evaluate its ongoing investment in Colstrip,
including the possibility of PGE's exit from the generation facility. See Note
8, Contingencies, in the Notes to Condensed Consolidated Financial Statements in
Item 1.-"Financial Statements" for information regarding legal proceedings
related to Colstrip.

Any reduction in generation from Colstrip has the potential to provide capacity
on the Colstrip Transmission facilities, which stretch from eastern Montana to
near the western end of that state to serve markets in the Pacific Northwest and
neighboring states. PGE has a 15% ownership interest in, and capacity on, the
Colstrip Transmission
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Regulatory Matters



PGE focuses on providing reliable, clean power to customers at affordable prices
while providing a fair return to investors. To achieve this goal the Company
must execute effectively within its regulatory framework and maintain prudent
management of key financial, regulatory, and environmental matters that may
affect customer prices and investor returns. The following discussion provides
detail on such matters.

General Rate Case-In July 2021, PGE filed with the OPUC a general rate case
based on a 2022 test year. The filing requested an increase in PGE's annual
revenue requirement that, when combined with changes in supplemental schedules,
would result in an overall average increase of approximately 3.9% in customer
prices for 2022. The net price increase and annual revenue requirement included
a 2.0% average price increase as a result of higher net variable power costs
(NVPC) expected in 2022, as reflected in the Annual Update Tariff (AUT) filed
with the OPUC in April 2021. The 2022 GRC filing sought recovery of base
business investments in upgrading the grid to improve reliability, resiliency,
and capability to deliver safe, reliable, clean electricity to customers.

PGE has invested heavily in its transmission and distribution system to meet the
needs of customers by addressing new and growing load and strengthening the grid
for new challenges with extreme weather and wildfires. These investments include
needed pole and underground wire replacements, substation upgrades, and other
additions, as well as the new Integrated Operations Center and the Advanced Data
Management System software platform.

The 2022 GRC also reflected significant investments geared toward protecting the
lives and property of Oregonians. As Oregon's weather gets hotter and drier,
increasing the risk of catastrophic wildfires, the Company is intensifying
efforts to keep the system safe from wildfire-related events and resilient from
weather and disaster-related crises. Key to these efforts are expansion of the
vegetation management program and system hardening to help mitigate potential
outages arising from wildfire and severe weather year-round.

The proposed net increase in annual revenue requirement in the 2022 GRC was based upon:

•A capital structure of 50% debt and 50% equity;

•A return on equity of 9.5%;

•A cost of capital of 6.94%; and

•A rate base of $5.7 billion.

PGE, OPUC staff, and certain customer groups reached an agreement that resolved cost of capital issues and allowed for:

•A capital structure of 50% debt and 50% equity;

•A return on equity of 9.5%; and

•A cost of capital of 6.83%, which reflects updates for actual and forecasted debt costs.

In addition, on January 18, 2022, PGE, OPUC staff, and certain customer groups filed a stipulation with the OPUC reflecting an agreement that resolved the annual revenue requirement, average rate base, and corresponding increase authorized in customer prices.

The stipulated agreement reflected a final revenue requirement that was based upon an average rate base of $5.6 billion and an annual revenue requirement increase of $74 million consisting of the following changes (in millions):

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As filed (includes $40 million related to NVPC)                               $     99
Load and NVPC Updates

Base Business Revenue Requirement Updates:

Faraday hydro capital-related revenue requirement (1)

                                                                    (18)

Cost of debt settlement including reductions to reflect actual financing costs

                                          (7)
   Level III outage annual regulatory accrual (2)                       (7)

Other reductions to rate base and operating and maintenance expenses

                                                    (5)
   Other various modifications to reflect actual costs                  (4)
     Subtotal

(41)


As revised (includes $64 million related to NVPC) (3)

$ 74




(1) The Faraday improvement capital project will not be placed in-service as of
May 9, 2022, and the capital-related revenue requirement was removed and can be
addressed in the next GRC proceeding. As of March 31, 2022, the construction
work-in-progress balance associated with Faraday was $116 million, including an
allowance for funds used during construction (AFUDC).

(2) PGE is authorized to collect annually from retail customers to cover
incremental expenses related to major storm damages, and to defer any amount not
utilized in the current year. In the 2022 GRC, the Company requested an annual
collection increase from $4 million to $11 million, and agreed to retain the
annual collection at $4 million.

(3) Total revenue requirement increase to base rates is $83 million, of which $9 million is not considered incremental as it is already included in current customer prices.



Further, the parties agreed to eliminate PGE's decoupling mechanism upon the
effective date of new customer prices pursuant to this case. Throughout the
remainder of 2022, estimated collections from, or refunds to, customers will be
pro-rated based on the effective date of new customer prices per the 2022 GRC
and expected to be amortized in customer prices in 2024 over a one-year period.
The decoupling mechanism provides a means of recovery or refund of margin lost
or gained as a result of changes in weather-adjusted energy use per customer in
comparison to levels projected in customer prices. For further information on
the decoupling mechanism, see "Decoupling" in this Overview section.
On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations
agreed to by the parties to the proceeding, including the annual revenue
requirement, cost of capital, capitalization ratio, and the elimination of the
decoupling mechanism. Key elements of the OPUC's Order also included:
•establishment of a balancing account for the Company's major storm damage
recovery mechanism;
•denial of PGE's proposal for a secondary phase of the 2022 GRC regarding the
Faraday capital improvement project. PGE can pursue recovery in the Company's
next GRC;
•establishment of a deferral that would require PGE to defer and refund, subject
to an earnings test, the revenue requirement associated with Boardman included
in customer prices following plant closure in 2020 (for more information see
"Deferral of Boardman Revenue Requirement" within this "Overview" section); and
•creation of an earnings test for the deferrals for the 2020 Wildfire Emergency
and the February 2021 Ice Storm and Damage that is to be applied on a
year-by-year basis.

As a result of the earnings tests outlined in the OPUC's Order, the Company has
released deferrals associated with the year ended 2020, resulting in a pre-tax,
non-cash charge to earnings for the three months ended March 31, 2022 in the
estimated amount of $17 million. PGE does not expect to exceed its regulated
return on equity under the earnings test methodology approved by the OPUC for
2021 and 2022.

New customer prices as approved by the OPUC will become effective May 9, 2022.
Price changes for the AUT and the supplemental schedules items occurred January
1, 2022.

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Complete details of the 2022 GRC filing (OPUC Docket UE 394) and the resulting
OPUC Order are available on the OPUC Internet website at www.oregon.gov/puc.

COVID-19 Impacts-The COVID-19 pandemic has had a variety of adverse impacts on
economic activity. The Company has responded to the hardships many customers are
facing and has taken steps to support its customers and communities, including
temporarily suspending disconnections and late fees during the crisis,
developing time payment arrangements, and partnering with local non-profits to
soften the impacts on small businesses and low-income residential customers. As
a result of these activities and economic hardships, PGE has experienced an
increase in bad debt expense, lost revenue, and other incremental costs.

In March 2020, PGE filed an application with the OPUC for deferral of lost
revenue and certain incremental costs, such as bad debt expense, related to
COVID-19. The application requested the ability to defer incremental costs
associated with the COVID-19 pandemic but did not specify the precise scope of
the deferral, or the means by which PGE would recover deferred amounts. PGE,
other utilities under the OPUC's jurisdiction, intervenors, and OPUC Staff held
discussions regarding the scope of costs incurred by utilities that may qualify
for deferral under Docket UM 2114. The result of such discussions was an Energy
Term Sheet (Term Sheet), which dictates costs in scope for deferral but is
silent to the timing of recovery of such costs. In September 2020, the OPUC
adopted a proposed OPUC Staff motion for Staff to execute stipulations
incorporating the terms of the Term Sheet. PGE's deferral application was
approved by the OPUC in October 2020 with final stipulations for the Term Sheet
approved in November 2020.

As of March 31, 2022 and December 31, 2021, PGE's deferred balance was
$35 million and $36 million, respectively, 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 $16 million to $18
million for the year-ended 2022. PGE expects to cease deferring incremental bad
debt expense associated with customers who are not on a time payment
arrangement, after September 30, 2022. Pursuant to the earnings tests outlined
in the OPUC's Order in the 2022 GRC, the Company has released deferrals
associated with the year ended 2020, resulting in a pre-tax charge to earnings
for the three months ended March 31, 2022 in the estimated amount of $2 million.
Amortization of any deferred costs will remain subject to OPUC review prior to
amortization in customer prices and would be subject to an earnings review.

PGE believes the amounts deferred are probable of recovery as the Company's
prudently incurred costs were in response to the unique nature of the COVID-19
pandemic health emergency. The OPUC has significant discretion in making the
final determination of recovery. The OPUC's conclusion of overall prudence,
including an earnings review, could result in a portion, or all, of PGE's
deferral being disallowed for recovery. Such disallowance would be recognized as
a charge to earnings.

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, which led to
the identification and activation of a 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 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.

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. Pursuant to Oregon Senate Bill 762, which was passed in June 2021,
PGE submitted a risk-based wildfire protection plan to the OPUC in December
2021. In Order 22-129, the OPUC did not adopt any rate adjustment mechanisms,
but rather invited PGE to submit a filing proposing a cost
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recovery mechanism for incremental wildfire costs consistent with SB 762 and
establishing an ongoing review for reasonableness.

PGE continues to incur costs to address fire-damaged vegetation, debris and
hazards both in and outside of PGE's property and right-of-way, and other
wildfire mitigation costs. In October 2020, the OPUC formally approved PGE's
request for deferral of 2020 wildfire-related costs. As of March 31, 2022 and
December 31, 2021, PGE's cumulative deferred costs related to the 2020 wildfire
response was $38 million and $45 million, respectively. Pursuant to the earnings
tests outlined in the OPUC's Order in the 2022 GRC, the Company has released
deferrals associated with the year ended 2020, resulting in a pre-tax charge to
earnings for the three months ended March 31, 2022 in the estimated amount of
$15 million.

The Company's deferral application for expenses related to wildfire mitigation, filed in 2019 under OPUC Docket UM 2019, has not yet been approved by the OPUC.

February 2021 Ice Storms and Damage-In February 2021, a historic set of storms
involving heavy snow, winds and ice impacted the United States, including PGE's
service territory. Oregon'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, 2022, PGE has incurred an estimated $108
million in incremental costs due to the storms, of which $36 million were
capital and recorded to Electric utility plant, net and $72 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 the
first quarter of 2021, PGE exhausted its storm collection balance for 2021 of $9
million, which was used to offset operating expenses. In December 2021, PGE and
parties in the 2022 GRC reached a settlement, subject to OPUC approval, to
restore the storm collection balance for the $9 million used in 2021 and to
defer the resulting balance of $9 million into the February 2021 ice storm and
damage regulatory asset.

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, 2022, the Company has deferred a total of $71 million, including
interest, related to incremental operating expenses due to the storms. PGE
incurred and deferred costs related to replacing and rebuilding PGE facilities
damaged by the storms, as well as addressing vegetation and other resulting
debris and hazards both in and outside of PGE's property and right-of-way. PGE
received OPUC Order No. 22-020 approving the February storms deferral in the
first quarter of 2022. While the Company believes the full amount of the
deferral is probable of recovery given PGE's prudently incurred costs were in
response to the unique and unprecedented nature of the storms, the OPUC has
significant discretion in making the final determination of recovery. The OPUC's
conclusion of overall prudence, including an earnings test, could result in a
portion, or all, of PGE's deferral being disallowed for recovery. Such
disallowance would be recognized as a charge to earnings.

Declared states of emergency-In September 2021, the OPUC issued an order that
approved a pre-authorized deferral of costs associated with declared states of
emergency. Qualifying events would include federal or state declared emergencies
with impacts on PGE's service territory. Previously the Company had to file a
request for deferred accounting when an event of that nature occurred, and had
to seek OPUC approval of such deferred accounting applications to be effective.
With this order, PGE would provide notice of an event that qualifies within 30
days of the declared state of emergency and would not need to seek OPUC approval
to use deferred accounting to track incremental costs related to the emergency.
The OPUC maintains responsibility to review utility requests to amortize
deferred amounts in customer prices including a review of utility prudence in a
future proceeding, among other requirements. PGE has not recorded any costs
under this deferral order.
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Power Costs-Pursuant to the AUT process, PGE annually files an estimate of power
costs for the following year. As approved by the OPUC, the 2022 AUT included a
final increase in power costs for 2022, and a corresponding increase in annual
revenue requirement, of $64 million from 2021 levels, which were reflected in
customer prices effective January 1, 2022. For 2021, actual NVPC was above
baseline NVPC by $62 million, which was outside the established deadband range.
Pursuant to the Company's power cost adjustment mechanism (PCAM) and related
earnings test, PGE has deferred 90% of the excess variance for 2021, or $28
million, which is expected to be collected from customers. See "Power
Operations" within this Overview section of Item 2 for more information
regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism-The U.S.
Environmental Protection Agency (EPA) has listed PGE as one of over one hundred
Potentially Responsible Parties (PRPs) related to the remediation of the
Portland Harbor Superfund site. As of March 31, 2022, significant uncertainties
still remained concerning the precise boundaries for clean-up, the assignment of
responsibility for clean-up costs, the final selection of a proposed remedy by
the EPA, and the method of allocation of costs amongst PRPs. It is probable that
PGE will share in a portion of these costs. In a Record of Decision issued in
2017, the EPA outlined its selected remediation plan for clean-up of the
Portland Harbor site, which had an estimated total cost of $1.7 billion.
Stakeholders have raised concerns that EPA's cost estimates are understated, and
PGE estimates undiscounted total remediation costs for Portland Harbor per the
ROD could range from $1.9 billion to $3.5 billion. The Company does not
currently have sufficient information to reasonably estimate the amount, or
range, of its potential costs for investigation or remediation of Portland
Harbor. However, the Company may obtain sufficient information, prior to the
final determination of allocation percentages among PRPs, to develop a
reasonable estimate, or range, of its potential liability that would require
recording an estimate, or low end of the range. The Company's liability related
to the cost of remediating Portland Harbor could be material to PGE's financial
position. The impact of such costs to the Company's results of operations is
mitigated by the PHERA mechanism. As approved by the OPUC, the Company's
recovery mechanism allows the Company to defer and recover estimated liabilities
and incurred environmental expenditures related to the Portland Harbor Superfund
Site through a combination of third-party proceeds, including, but not limited
to, insurance recoveries, and customer prices, as necessary. The mechanism
established annual prudency reviews of environmental expenditures and
third-party proceeds, and annual expenditures in excess of $6 million, excluding
contingent liabilities, are subject to an annual earnings test. PGE's results of
operations may be impacted to the extent such expenditures 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, was
intended to provide for recovery of margin lost as a result of a reduction in
electricity sales attributable to energy efficiency, customer-owned generation,
and conservation efforts by residential and certain commercial customers. The
mechanism provided for collection from (or refund to) customers if
weather-adjusted use per customer was less (or more) than that projected in the
Company's most recent GRC.

Collections under the decoupling mechanism were subject to an annual limitation
of 2% of revenues for each eligible customer class, based on the net prices in
effect for the applicable tariff schedule at the time of collection. For
collections recorded in 2022, the 2% limit will be applied to the net prices for
the applicable tariff schedules that will be in effect on January 1, 2024. No
limit existed for any potential refunds under the decoupling mechanism, thus
increased demand from residential customers since the onset of the COVID-19
pandemic had resulted in larger estimated refunds under the decoupling
mechanism, which had largely offset the revenue increases that had resulted from
higher residential demand.

In the 2022 GRC, parties reached an agreement that has eliminated PGE's decoupling mechanism upon the effective date of new customer prices pursuant to the case, which are expected to begin May 9, 2022. Pursuant to the GRC


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Order, the OPUC adopted the agreement such that deferrals will cease, although
amortization of previously recorded deferrals will continue as scheduled until
collected or refunded in future customer prices.

For the three months ended March 31, 2022, the Company recorded an estimated
refund of $2 million and a collection of $1 million from residential and
commercial customers, respectively, that resulted from variances between actual
weather-adjusted use per customer and that projected in the 2019 GRC. The
Company continues to see higher weather-adjusted use per customer from
residential customers that are spending more time at home and lower use per
customer from commercial customers that are adversely affected by the COVID-19
pandemic.

As of December 31, 2021, PGE had recorded a total estimated refund of $10 million that, subject to OPUC approval, will be refunded to customers over a one-year period, which would begin January 1, 2023.



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 2019 GRC. The application stated a
deferral is required for customers to adequately capture the reduction in
revenue requirement beginning on October 15, 2020, the date Boardman ceased
operations. In October 2021, intervenors filed a motion with the OPUC requesting
to consolidate the open Boardman deferral docket with PGE's open 2022 GRC
docket. The Administrative Law Judge denied the consolidation, although did
provide an opportunity to use the 2022 GRC proceeding to settle any issues with
deferrals.

PGE estimated the revenue requirement for Boardman to be $14 million for the
period ended December 31, 2020 plus an additional $66 million for the year ended
December 31, 2021 and $17 million for the three months ended March 31, 2022.

In the 2022 GRC Order, the OPUC found that the deferral was warranted with
amortization subject to an earnings test. Based on the earnings test, PGE does
not expect to record a refund related to Boardman. Customer prices resulting
from the 2022 GRC Order will no longer include any revenue requirement related
to Boardman when new customer prices take effect on May 9, 2022.

Renewable Recovery Framework-As previously authorized by the OPUC, a primary
method available to recover costs associated with renewable resources is the
RAC. 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. There have been no significant filings made under the RAC
during 2022.

Operating Activities

In combination with electricity provided by its own generation portfolio, to
meet its retail load requirements and balance its energy supply with customer
demand, PGE purchases and sells electricity in the wholesale market. The Company
also performs portfolio management and wholesale market sales services for third
parties in the region. PGE also participates in the California Independent
System Operator'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
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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.

                                                                       Three Months Ended March 31,      % Increase (Decrease)
                                                                                                               in Energy
                                                                                                  2022        Deliveries           2021

Energy deliveries (MWhs in thousands):
Retail:
Residential                                                                                                        2,216                      2,239           (1) %
Commercial                                                                                                         1,634                      1,564            4  %
Industrial                                                                                                           974                        897            9  %
Subtotal                                                                                                           4,824                      4,700            3  %
Direct access:
Commercial                                                                                                           131                        150          (13) %
Industrial                                                                                                           413                        359           15  %
Subtotal                                                                                                             544                        509            7  %
Total retail energy deliveries                                                                                     5,368                      5,209            3  %
Wholesale energy deliveries                                                                                        1,507                      1,245           21  %
Total energy deliveries                                                                                            6,875                      6,454            7  %




                                                                      Three Months Ended March 31,
                                                                                     2022                          2021

Average number of retail customers:
Residential                                                                                       806,553          88  %             797,602     88  %
Commercial                                                                                        111,668          12                110,703     12
Industrial                                                                                            192           -                    193      -
Direct access                                                                                         550           -                    601      -
Total                                                                                             918,963         100  %        909,099         100  %

Total retail energy deliveries for the three months ended March 31, 2022 increased 3% compared with the three months ended March 31, 2021, driven by strong demand from the industrial customer class.



The industrial class has experienced an increase in energy deliveries, due
primarily to continued growth in the high tech and digital services sectors,
which saw lesser impacts from the COVID-19 pandemic closures than other sectors.
Residential usage continues to be elevated as remote and hybrid work schedules
remain in place across the Company's service area, although total deliveries
declined slightly, reflecting the impact of relative temperatures as 2022 had
fewer heating degree-days.

The following table indicates the number of heating degree-days for the three
months ended March 31, 2022 and 2021, along with the current 15-year averages
based on weather data provided by the National Weather Service, as measured at
Portland International Airport:
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                                                          Heating Degree-days
                                                     2022              2021         Avg.

      January                                              710          620          721
      February                                             591          641          598
      March                                                460          544          527

      Year-to-date                                       1,761        1,805        1,846
      (Decrease) from the 15-year average                   (5) %

(2) %





After adjusting for the effects of weather, retail energy deliveries for the
three months ended March 31, 2022 increased 4.4% compared to the same period of
2021. The increase reflects increases of 10% in industrial deliveries, 3% in
commercial energy deliveries, and 2% in residential energy deliveries.
Residential weather-adjusted average usage per customer ticked up slightly
during the first quarter 2022 compared with 2021, while growth of 1.1% in the
average number of residential customers contributed to the increased energy
deliveries in total.

The Company's cost-of-service opt-out program caps participation by customers in
the fixed three-year and minimum five-year opt-out programs, which account for
the majority of energy delivered to Direct Access customers who purchase their
energy from ESSs. This cap would have limited energy deliveries to these
customers to an amount equal to approximately 12% of PGE's total retail energy
deliveries for the first three months of 2022.

In early February 2020, PGE began offering service to customers under an OPUC
created New Large Load Direct Access program for unplanned, large, new loads and
large load growth at existing customer sites. With the adoption of the New Large
Load Direct Access program, which is capped at 119 MWa, as much as 17% 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 2022 and 2021.

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, 2022 and
2021:
                                                                          Actual energy provided                   Actual energy provided as a
                                                                           compared to projected                   percentage of total retail
                                        Plant availability (1)                  levels (2)                                    load

                                          2022             2021                           2022           2021                        2022          2021
Generation:
Thermal:
Natural gas                                      92  %         94  %                          79  %         114  %                       42  %         48  %
Coal (3)                                         96            94                            110            103                          12            12
Wind (4)                                         74            94                             83            129                           8            11
Hydro                                            96            85                             81             81                           5             6


(1)Plant availability represents the percentage of the period plants were
available for operations, which is impacted by planned maintenance and forced,
or unplanned, outages.
(2)Projected levels of energy are included as part of PGE's AUT. Such
projections establish the power cost component of retail prices for the
following calendar year. Any shortfall is generally replaced with power from
higher cost sources, while any excess generally displaces power from higher cost
sources.
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Table of Contents (3)Plant availability reflects Colstrip, which PGE does not operate. (4)Plant availability excludes Wheatridge, which PGE does not operate.



Energy received from PGE-owned and jointly-owned thermal plants during the three
months ended March 31, 2022 compared to 2021 decreased 7%. In 2022 generation at
the Company's natural gas-fired plants decreased due to less favorable gas
prices, partially offset by an increase in coal-fired generation. Energy
expected to be received from thermal resources is projected annually in the AUT
based on forecast market prices, variable costs to run the plant, and the
constraints of the plant. PGE's thermal generating plants require varying levels
of annual maintenance, which is generally performed during the second quarter of
the year.

Total energy received from hydroelectric generation sources, both PGE-owned
generation and purchased, increased 27% during the three months ended March 31,
2022 compared to 2021. Energy purchased from mid-Columbia and other regional
hydroelectric projects increased 38% and energy generated by the Company-owned
facilities decreased 14% in the three months ended March 31, 2022 partially due
to PGE's sale of 16.66% of its ownership interest in Pelton/Round Butte to the
Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS), effective
January 1, 2022. PGE purchases 100% of the CTWS's share of the project output.
Energy expected to be received from hydroelectric resources is projected
annually in the AUT based on a modified hydro study, which utilizes 80 years of
historical stream flow data. See "Purchased power and fuel" in the Results of
Operations section in this Item 2, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts decreased 24%
during the three months ended March 31, 2022 compared to 2021 primarily due to
unplanned plant outages during the period. Energy expected to be received from
wind generating resources is projected annually in the AUT based on historical
generation. Wind generation forecasts are developed using a 5-year rolling
average of historical wind levels or forecast studies when historical data is
not available.

Under PGE's PCAM, the Company may share with customers a portion of cost
variances associated with NVPC. Customer prices can be adjusted annually to
absorb a portion of the difference between the forecasted NVPC included in
customer prices (baseline NVPC) and actual NVPC for the year, if such
differences exceed a prescribed "deadband" limit, which ranges from $15 million
below to $30 million above baseline NVPC. To the extent actual NVPC, subject to
certain adjustments, is outside the deadband range, the PCAM provides for 90% of
the excess variance to be collected from, or refunded to, customers. Pursuant to
a regulated earnings test, a refund will occur only to the extent that it
results in PGE's actual regulated return on equity (ROE) for the given year
being no less than 1% above the Company's latest authorized ROE, while a
collection will occur only to the extent that it results in PGE's actual
regulated ROE for that year being no greater than 1% below the Company's
authorized ROE. The following is a summary of the results of the Company's PCAM
as calculated for regulatory purposes for the three months ended March 31, 2022
and 2021, respectively:

•For the three months ended March 31, 2022, actual NVPC was $10 million below
baseline NVPC. Based on forecast data, NVPC for the year ending December 31,
2022 is currently estimated to be below the baseline, and within the established
deadband range. Accordingly, no estimated refund to customers is expected under
the PCAM for 2022.

•For the three months ended March 31, 2021, actual NVPC was $13 million below
baseline NVPC. For the year ended December 31, 2021, actual NVPC was $62 million
above baseline NVPC, which was outside the established deadband range. Pursuant
to the PCAM, as PGE's preliminary regulatory ROE was below 8.5% pursuant to the
related earnings test PGE deferred $28 million, which represents 90% of the
excess variance expected to be collected from customers. A final determination
regarding the 2021 PCAM results will be made by the OPUC through a public filing
and review in 2022. The OPUC has significant discretion in making the final
determination of recovery. The OPUC's conclusion of overall prudence, including
an earnings review, could result in a portion, or all, of PGE's deferral being
disallowed for recovery. Such disallowance would be recognized as a charge to
earnings.

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Results of Operations

The following tables provide financial and operational information to be considered in conjunction with management's discussion and analysis of results of operations.

The results of operations are as follows for the periods presented (dollars in millions):



                                                                         Three Months Ended March 31,               % Increase
                                                                                                           2022     (Decrease)        2021
Total revenues                                                                                                   $         626                    $  609                   3  %
Operating expenses:
Purchased power and fuel                                                                                                   202                       169                  20  %
Generation, transmission and distribution                                                                                   90                        80                  13  %
Administrative and other                                                                                                    89                        86                   3  %
Depreciation and amortization                                                                                               99                       103                  (4) %
Taxes other than income taxes                                                                                               40                        38                   5  %
Total operating expenses                                                                                                   520                       476                   9  %
Income from operations                                                                                                     106                       133                 (20) %
Interest expense, net*                                                                                                      38                        34                  12  %
Other income:
Allowance for equity funds used during construction                                                                          3                         4                 (25) %
Miscellaneous income, net                                                                                                    -                         2                (100) %
Other income, net                                                                                                            3                         6                 (50) %
Income before income tax expense                                                                                            71                       105                 (32) %
Income tax expense                                                                                                          11                         9                  22  %
Net income                                                                                                       $          60                    $   96                 (38) %

* Includes an allowance for borrowed funds used during construction of $2 million for the three months ended March 31, 2022 and 2021, respectively.



Net income for the three months ended March 31, 2022 decreased $36 million from
the comparable period of 2021.
Total revenues increased as a result of higher retail energy deliveries,
primarily driven by continued growth in industrial demand, including high-tech
manufacturing. The revenue increase also reflects price increases authorized by
the OPUC as a result of the AUT, which are offset by higher power costs. The
impact of higher natural gas and wholesale electricity prices coupled with
increased customer demand also drove Purchased power and fuel expense up. Retail
revenues were impacted by a slightly lower average price mix in 2022 as a result
of the increased demand in the industrial sector. Wholesale revenues increased
primarily due to higher market prices. Increases in Operating expenses reflect
$17 million of previously deferred items that were disallowed as a result of the
2022 GRC order from the OPUC, and expenses related to service restoration costs
and continued vegetation management activities. Higher relative Income tax
expense in 2022 reflects the favorable impact of a local tax flow-through
adjustment that occurred in 2021.
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Total revenues consist of the following for the periods presented (dollars in
millions):

                                                              Three Months Ended March
                                                                        31,
                                                                      2022                    2021

Retail:
Residential                                                                   $  308          49  %       $  310         51  %
Commercial                                                                       178          29             162         26
Industrial                                                                        69          11              60         10
Direct Access*                                                                     8           1              11          2
Subtotal                                                                         563          90             543         89
Alternative revenue programs, net of amortization                                  1           -              (3)         -
Other accrued revenues, net                                                        -           -              13          2
Total retail revenues                                                            564          90             553         91
Wholesale revenues                                                                56           9              33          5
Other operating revenues                                                           6           1              23          4
Total revenues                                                                $  626         100  %       $  609        100  %

* Commercial revenues from Direct Access customers were $3 million for 2022 and $4 million for 2021, respectively. Industrial revenues from Direct Access customers were $5 million and $7 million for 2022 and 2021, respectively.



Total retail revenues-The following items contributed to the increase in Total
retail revenues for the three months ended March 31, 2022 compared to the same
period in 2021 as follows (dollars in millions):
                                                                                Three Months Ended
March 31, 2021                                                                $               553

Increase as a result of the AUT, approved by the OPUC (offset in Purchased power and fuel)

Increase from higher retail energy deliveries driven by customer load growth

Increase resulting from the combination of various supplemental tariffs and adjustments

                                                                                 1
  Recovery in Revenues of Storm related expenses in 2021                                      (11)

Decrease as a result of the change in the average price of energy deliveries due primarily to shift in mix among customer classes resulting from COVID-19 and increased industrial demand

                                                 (11)

Decrease attributed to alternative revenue programs related to the decoupling mechanism due primarily to increased residential use per customer

                                                                                       (3)
March 31, 2022                                                                $               564
Change in Total retail revenues                                               $                11



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, 2022, Wholesale revenues increased $23
million, or 70%, from the three months ended March 31, 2021 as a $16 million
increase from 16% higher average wholesale sales price was combined with a $7
million increase due to a 21% increase in sales volumes. The higher prices have
resulted from the overall economic recovery and macroeconomic factors impacting
the energy commodity markets.

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Other operating revenues were down $17 million for the three months ended March
31, 2022 compared with the same period in 2021. In the three months ended March
31, 2021, market conditions allowed the Company to sell excess natural gas not
needed to fuel generation at a gain of $10 million, whereas in 2022 such excess
gas was sold at a $6 million loss.

Purchased power and fuel expense includes the cost of power purchased and fuel
used to generate electricity to meet PGE's retail load requirements, as well as
the cost of settled electric and natural gas financial contracts.

The following items contributed to the change in Purchased power and fuel for
the three months ended March 31, 2022 compared to the same period in 2021
(dollars in millions, except for average variable power cost per Megawatt hours
(MWh)):
                                                                  Three Months Ended
  March 31, 2021                                                 $               169
  Increase related to average variable power cost per MWh                          3
  Increase related to total system load                                           30

  March 31, 2022                                                                 202
  Change in Purchased power and fuel                             $                33

  Average variable power cost per MWh:
  March 31, 2021                                                 $             27.14
  March 31, 2022                                                 $             30.34

  Total system load (MWhs in thousands):
  March 31, 2021                                                                 6,237
  March 31, 2022                                                                 6,648



For the three months ended March 31, 2022, the $3 million increase related to
the change in average variable power cost per MWh was driven by a 5% increase in
the average cost of purchased power, offset with a 9% decrease on the average
cost for the Company's own generation. The $30 million increase related to total
system load was primarily due to a 33% increase in deliveries of energy obtained
from purchased power resulting from the economic displacement of gas facilities
in the first quarter of 2022, in addition to increased retail load demand. This
was offset by a 10% decrease in the Company's own generation.
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PGE's sources of energy, total system load, and retail load requirement for the periods presented are as follows:

Three Months Ended March 31,


                                                                                         2022                          2021
Sources of energy (MWhs in thousands):
Generation:
Thermal:
Natural gas                                                                                                     2,149             32  %         2,383             38  %
Coal                                                                                                              610              9              582              9
Total thermal                                                                                                   2,759             41            2,965             47
Hydro                                                                                                             273              4              317              5
Wind                                                                                                              392              6              532              9
Total generation                                                                                                3,424             51            3,814             61
Purchased power:
Hydro*                                                                                                          1,562             23            1,129             18
Wind*                                                                                                             195              3              238              4
Solar*                                                                                                            113              2               92              1
Natural Gas                                                                                                         2              -                4              -
Waste, Wood and Landfill Gas*                                                                                      37              1               39              1
Source not specified                                                                                            1,315             20              921             15
Total purchased power                                                                                           3,224             49            2,423             39
Total system load                                                                                               6,648            100  %         6,237            100  %
Less: wholesale sales                                                                                          (1,507)                         (1,245)
Retail load requirement                                                                                         5,141                           4,992



*Includes power received from qualifying facilities under the Public Utility
Regulatory Policies Act of 1978 (PURPA) of 6 MWh in 2022 and 2021 from Hydro
resources, 6 MWh in 2022 and 2021 from Wind resources, 104 MWh in 2022 and 88
MWh in 2021 from Solar resources, and 20 MWh in 2022 and 19 MWh in 2021 from
Waste, Wood and Landfill Gas resources.

The following table presents the forecast April-to-September 2022 and the actual 2021 runoff at particular points of major rivers relevant to PGE's hydro resources:

Runoff as a Percent of Normal*


                        Location                              2022 Forecast                   2021 Actual
Columbia River at The Dalles, Oregon                                       95  %                           82  %
Mid-Columbia River at Grand Coulee, Washington                            103                              89
Clackamas River at Estacada, Oregon                                       104                              70
Deschutes River at Moody, Oregon                                           92                              84

* 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.


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Actual NVPC for the three months ended March 31, 2022 increased compared to the
same period in 2021 as follows (dollars in millions):
                                                      Three Months Ended
              March 31, 2021                         $               136
              Purchased power and fuel expense                        33
              Wholesale revenues                                     (23)
              March 31, 2022                         $               146
              Change in NVPC                         $                10



For further information regarding NVPC in relation to the PCAM, see "Purchased
power and fuel expense" and "Revenues" within this "Results of Operations" for
more details.

For the three months ended March 31, 2022 and 2021, actual NVPC was $10 million and $13 million below baseline NVPC, respectively.



Based on forecast data, NVPC for the year ending December 31, 2022 is currently
estimated to be below the baseline, and within the deadband. Accordingly, no
estimated refund to customers is expected under the PCAM for 2022.

Generation, transmission and distribution increased as follows for the three
months ended March 31, 2022 compared to the same period in 2021 (dollars in
millions):
                                                                                Three Months Ended
March 31, 2021                                                                $                80

Release of previously deferred amounts pursuant to April OPUC 2022 GRC

Order

Higher distribution vegetation management, inspection, and maintenance expenses

                                                                                        8
February 2021 wind and ice storm restoration expenses                                         (13)
Miscellaneous expenses                                                                         (1)
March 31, 2022                                                                $                90
Change in Generation, transmission and distribution                           $                10

PGE experienced higher Generation, transmission and distribution expenses largely from vegetation management activities coupled with a strong labor market and rising cost of materials and supplies.

Administrative and other increased for the three months ended March 31, 2022 compared to the same period in 2021 as follows (dollars in millions):


                                                               Three Months

Ended


     March 31, 2021                                           $                86
     Higher employee compensation and benefits expenses                         2
     Lower professional service expenses                                       (1)
     Miscellaneous expenses                                                     2
     March 31, 2022                                           $                89
     Change in Administrative and other                       $                 3



Higher Administrative and other expenses reflect increases for employee wage and
benefit expenses and outside services, including labor, driven by a strong labor
market, as well as the cost of materials.

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Depreciation and amortization expense decreased $4 million in the three months
ended March 31, 2022 compared to the same period in 2021, driven by an $8
million decrease due to regulatory amortization, partially offset by higher
depreciation from net plant additions.

Taxes other than income taxes expense increased $2 million in the three months ended March 31, 2022 compared with 2021, driven by higher franchise tax expenses.

Interest expense, net increased $4 million in the three months ended March 31, 2022 compared to the same period in 2021 due to higher leasing expenses and higher long-term debt balances.



Other income, net decreased $3 million for the three months ended March 31, 2022
compared to the same period in 2021. The decrease was driven by unfavorable
market changes on the non-qualified benefit trust, partially offset by higher
interest income on regulatory deferral balances.

Income tax expense increased $2 million for three months ended March 31, 2022,
compared to the same period in 2021. The increase was driven by a cumulative
catch-up adjustment recorded in the first quarter of 2021 to defer and recognize
a regulatory asset for previously recorded deferred income tax expenses on a
certain local flow-through tax. The increase was partially offset by lower 2022
pre-tax income. See Note 10, Income Taxes, in the Notes to Condensed
Consolidated Financial Statements in Item 1.-"Financial Statements," for more
information.

Critical Accounting Policies and Estimates



There have been no material changes to the Company's critical accounting
policies and estimates as previously disclosed in Item 7 of the Company's Annual
Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on
February 17, 2022.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity



PGE's access to short-term debt markets, including revolving credit from banks,
helps provide necessary liquidity to support the Company's current operating
activities, including the purchase of power and fuel. Long-term capital
requirements are driven largely by capital expenditures for distribution,
transmission, and generation facilities to support both new and existing
customers, repairs from major storm damage, information technology systems, and
debt refinancing activities. PGE's liquidity and capital requirements can also
be significantly affected by other working capital needs, including margin
deposit requirements related to wholesale market activities, which can vary
depending upon the Company's forward positions and the corresponding price
curves.

The following summarizes PGE's cash flows for the periods presented (dollars in
millions):

                                                                   Three Months Ended March 31,
                                                                    2022                   2021
Cash and cash equivalents, beginning of period               $            52          $        257
Net cash provided by (used in):
Operating activities                                                     249                   168
Investing activities                                                    (154)                 (162)
Financing activities                                                     (37)                 (128)
Increase (decrease) in cash and cash equivalents                          58                  (122)
Cash and cash equivalents, end of period                     $           110          $        135



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Latest news about Portland General Electric Company

Portland General Electric Raises Quarterly Dividend 5.3% to $0.50 Per Share, Payable Around July 15 to Shareholders on June 24	Apr. 22	MT
Portland General Electric Company Declares Quarterly Dividend, Payable on or Before July 15, 2024	Apr. 19	CI
Lawyers who voided Elon Musk's pay as excessive want $6 bln fee	Mar. 01	RE
Barclays Cuts Price Target on Portland General Electric to $42 From $45, Maintains Overweight Rating	Feb. 21	MT
Transcript : Portland General Electric Company, Q4 2023 Earnings Call, Feb 16, 2024	Feb. 16
Stock Futures Mostly Rise Pre-Bell Ahead of Producer Price Index Report; Asia, Europe Strong	Feb. 16	MT
Portland General Electric's Q4 Earnings Rise; 2024 Adjusted Earnings Guidance Issued	Feb. 16	MT
North American Morning Briefing : S&P 500 Seen -2-	Feb. 16	DJ
Portland General Electric Company Reports Earnings Results for the Full Year Ended December 31, 2023	Feb. 16	CI
Portland General Electric Keeps Quarterly Dividend of $0.475 a Share, Payable Around April 15 to Shareholders as of March 22	Feb. 12	MT
Portland General Electric Company Declares Quarterly Dividend, Payable on or Before April 15, 2024	Feb. 09	CI
North American Morning Briefing : Rate Doubts Keep -2-	Feb. 06	DJ
Sector Update: Energy Stocks Mixed in Late Monday Afternoon Trading	Feb. 05	MT
Portland General Electric Shares Fall After BofA Securities Downgrade	Feb. 05	MT
BofA Securities Downgrades Portland General Electric to Neutral From Buy, Adjusts Price Target to $43 From $55	Feb. 05	MT
North American Morning Briefing : Microsoft Kicks -2-	Jan. 30	DJ
UBS Upgrades Portland General Electric to Buy From Neutral, Cuts Price Target to $45 From $47	Jan. 29	MT
Barclays Cuts Portland General Electric's Price Target to $45 From $47, Keeps Overweight Rating	Jan. 22	MT
US cold snap leaves over 100,000 without power in Oregon	Jan. 19	RE
Frigid temps cut US natural gas supply as demand soars, Texas faces possible shortfall	Jan. 14	RE
Frigid temps cut US natgas supply as demand soars, Texas faces possible shortfall	Jan. 14	RE
Crown Castle gives in to Elliott's demands with fiber unit review, board changes	Dec. 20	RE
North American Morning Briefing : Traders Eye -2-	Dec. 12	DJ
Barclays Upgrades Portland General Electric to Overweight From Equal-Weight, Raises Price Target to $47 From $44	Dec. 11	MT
Ladenburg Thalmann Initiates Portland General Electric at Buy Rating With $43 Price Target	Nov. 09	MT

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Company Profile

Portland General Electric Company is an integrated energy company that generates, transmits and distributes electricity. The Company is engaged in the generation, wholesale purchase and sale, transmission, distribution, and retail sale of electricity to customers in the state of Oregon (State). The Company participates in the wholesale market through the purchase and sale of electricity and natural gas in an effort to obtain reasonably-priced power to serve its retail customers. The Company meets its retail load requirement with both Company-owned generation and power purchased on the wholesale market. The Company has five natural gas-fired generating facilities: PW1, PW2, Beaver, Coyote Springs Unit 1 (Coyote Springs), and Carty Generating Station (Carty). It owns and operates two wind farms, Biglow Canyon Wind Farm (Biglow Canyon) and Tucannon River Wind Farm (Tucannon River). Biglow Canyon is located in Sherman County, Oregon. Tucannon River is located in southeastern Washington.

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Electric Utilities

Calendar

05:00am - Q1 2024 Earnings Release

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Ratings for Portland General Electric Company

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Mean consensus

OUTPERFORM

Number of Analysts

Last Close Price

43.69 USD

Average target price

48.17 USD

Spread / Average Target

+10.25%

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Portland General Electric Company

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US7365088472

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PORTLAND GENERAL ELECTRIC CO /OR/ Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-Q)

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