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 FERC and OPUC with respect to
allowed rates of return, financings, electricity pricing and price structures,
acquisition and disposal of facilities and other assets, construction and
operation of plant facilities, transmission of electricity, recovery of power
costs and capital investments, and current or prospective wholesale and retail
competition;

•economic conditions that result in decreased demand for electricity, reduced
revenue from sales of excess energy during periods of low wholesale market
prices, impaired financial stability of vendors and service providers and
elevated levels of uncollectible customer accounts;
•changing customer expectations and choices that may reduce customer demand for
its services may impact PGE's ability to make and recover its investments
through rates and earn its authorized return on equity, including the impact of
growing distributed and renewable generation resources, changing customer demand
for enhanced electric services, and an increasing risk that customers procure
electricity from registered ESSs or community choice aggregators;
•the outcome of legal and regulatory proceedings and issues including, but not
limited to, the matters described in Note 19, Contingencies, in the Notes to
Consolidated Financial Statements in Item 8.- "Financial Statements and
Supplementary Data" of this Annual Report on Form 10-K;
•unseasonable or extreme weather and other natural phenomena, which could affect
customers' demand for power and PGE's ability and cost to procure adequate power
and fuel supplies to serve its customers, and could increase the Company's costs
to maintain its generating facilities and transmission and distribution systems;
•operational factors affecting PGE's power generating facilities, including
forced outages, hydro and wind conditions, and disruption of fuel supply, any of
which may cause the Company to incur repair costs or purchase replacement power
at increased costs;
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•complications arising from PGE's jointly-owned generating facilities, including
changes in ownership, adverse regulatory outcomes or legislative actions, or
operational failures that result in legal or environmental liabilities or
unanticipated costs related to replacement power or repair costs;
•failure to complete capital projects on schedule and within budget or the
abandonment of capital projects, either of which could result in the Company's
inability to recover project costs;
•volatility in wholesale power and natural gas prices that could require PGE to
post additional collateral or issue additional letters of credit pursuant to
power and natural gas purchase agreements;
•changes in the availability and price of wholesale power and fuels, including
natural gas and coal, and the impact of such changes on the Company's power
costs;
•capital market conditions, including availability of capital, volatility of
interest rates, reductions in demand for investment-grade commercial paper, as
well as changes in PGE's credit ratings, any of which could have an impact on
the Company's cost of capital and its ability to access the capital markets to
support requirements for working capital, construction of capital projects, and
the repayments of maturing debt;
•future laws, regulations, and proceedings that could increase the Company's
costs of operating its thermal generating plants, or affect the operations of
such plants by imposing requirements for additional emissions controls or
significant emissions fees or taxes, particularly with respect to coal-fired
generating facilities, in order to mitigate carbon dioxide, mercury and other
gas emissions;
•changes in, and compliance with, environmental laws and policies, including
those related to threatened and endangered species, fish, and wildlife;
•the effects of climate change, including changes in the environment that may
affect energy costs or consumption, increase the Company's costs, or adversely
affect its operations;
•changes in residential, commercial, or industrial customer growth, or
demographic patterns, in PGE's service territory;
•the effectiveness of PGE's risk management policies and procedures;
•cybersecurity attacks, data security breaches, or other malicious acts that
cause damage to the Company's generation, transmission, or distribution
facilities, information technology systems, or result in the release of
confidential customer, employee, or Company information;
•employee workforce factors, including potential strikes, work stoppages,
transitions in senior management, and the ability to recruit and retain
appropriate talent;
•new federal, state, and local laws that could have adverse effects on operating
results;
•political and economic conditions;
•natural disasters and other risks, such as pandemic, earthquake, flood,
drought, lightning, wind, and fire;
•the impact of widespread health developments, including the global coronavirus
(COVID-19) pandemic, and responses to such developments (such as voluntary and
mandatory quarantines, including government stay at home orders, as well as shut
downs and other restrictions on travel, commercial, social, and other
activities), which could materially and adversely affect, among other things,
demand for electric services, customers' ability to pay, supply chains,
personnel, contract counterparties, liquidity and financial markets;
•changes in financial or regulatory accounting principles or policies imposed by
governing bodies;
•acts of war or terrorism; and
•the impact of the recommendations on the Company and its operations based on
the review conducted by the Special Committee relating to energy trading losses,
the time and expense incurred in implementing the recommendations of the Special
Committee, and any reputational damage to the Company relating to the matters
underlying the Special Committee's review.

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

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. MD&A should
be read in conjunction with the Company's consolidated financial statements
contained in this report, and other periodic and current reports filed with the
SEC.

PGE is a vertically-integrated electric utility engaged in the generation,
transmission, distribution, and retail sale of electricity in the state of
Oregon, as well as the wholesale purchase and sale of electricity and natural
gas in order to meet the needs of its retail customers. The Company generates
revenues and cash flows primarily from the sale and distribution of electricity
to retail customers in its service territory. In addition, the Company
participates in the wholesale market by purchasing and selling electricity and
natural gas in an effort to obtain reasonably-priced power for its retail
customers.

Energy Trading



PGE is exposed to commodity price risk as its primary business is to provide
electricity to its retail customers. The Company expects to manage commodity
price volatility within net variable power costs by engaging in energy trading
activities. The Company does not intend to engage in trading activities for
non-retail purposes.

PGE personnel entered into a number of energy trades during 2020, with
increasing volume accumulating late in the second quarter and into the third
quarter, resulting in significant exposure to the Company. In August 2020, a
portion of energy trading positions in PGE's energy portfolio experienced
significant losses as wholesale electricity prices increased substantially at
various market hubs due to extreme weather conditions, constraints to regional
transmission facilities, and changes in power supply in the West. During this
time period, the CAISO declared a Stage 3 Electrical Emergency and ordered the
first rolling blackouts in the state of California since 2001.

As a result of the convergence of these conditions, the Company's energy
portfolio experienced realized losses of $127 million on these positions in
2020. PGE determined the energy trading positions that led to the losses were
outside the Company's acceptable risk tolerances, and the Company will not
pursue regulatory recovery of the associated losses. PGE will also exclude the
impacts of the realized losses from its regulatory earnings tests. The increase
in net variable power costs due to this trading activity has been recognized in
PGE's results of operations. PGE no longer has net market exposure from the
energy trading positions that led to these losses.

PGE and its external consultants have performed a full operational review of the
Company's energy supply risk management policies, procedures and personnel. In
addition, the PGE Board of Directors formed a Special Committee comprising five
independent Board members to review the energy trading that led to the losses
and the Company's procedures and controls related to the trading, and to make
recommendations to the Board for appropriate action. The Special Committee
retained independent legal advisors. On December 18, 2020, PGE announced that
the Special Committee concluded its independent review of the energy trading
activity that led to the losses incurred in the third quarter of 2020. The
Special Committee concluded that the trades were ill-conceived and revealed
opportunities for improving the Company's energy trading policies and practices.
Additionally, the Board of Directors concluded that the actions the Company
began taking in August to enhance oversight of energy trading and associated
risk management reporting, policies, and practices were consistent with the
Special Committee's recommendations and will be monitored by the Board of
Directors through enhanced reporting. These actions are expected to strengthen
the Company and include:
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•Added expertise: PGE brought in additional experienced risk management
personnel and replaced the Power Operations general manager with a new leader;
•Strengthened trading policies: Power Operations personnel are operating under
revised policies designed to prevent positions of the type that led to the
losses. The improved policies place controls on the ability of personnel to
enter into wholesale energy transactions to the extent that PGE does not have
physical or financial delivery capability;
•Enhanced risk reporting: Energy trading activity reporting has been improved to
ensure greater visibility into portfolio risk;
•Changed reporting structures: Energy Trading Risk Management now reports
through a Risk and Compliance team that reports to the Chief Executive Officer.
Effective January 1, 2021, Power Operations reports to the Vice President of
Strategy, Regulation and Energy Supply; and
•Changed personnel: The individuals who previously were placed on leave are no
longer with the Company.

For further information regarding legal proceedings associated with this matter, see "Shareholder Lawsuits" in Note 19, Contingencies in the Notes to Consolidated Financial Statements in Item 8.-"Financial Statements and Supplementary Data."

COVID-19 Impacts



The COVID-19 pandemic has adversely impacted economic activity and conditions
worldwide, including workforces, liquidity, capital markets, consumer behavior,
supply chains, and macroeconomic conditions. In the state of Oregon, the
Governor issued an executive order on March 23, 2020 directing Oregon residents
to stay at home except for essential activity and mandating closure of
businesses for which close personal contact was difficult or impossible to
avoid. This order was rescinded May 14, 2020 in a new executive order announcing
a phased approach for reopening Oregon's economy. The subsequent phased
reopening approach has not allowed all businesses to reopen, or has allowed
reopening only at reduced capacity to meet requirements for social distancing.
The continued loosening of restrictions is contingent upon the successful
reduction of cases.

Retail loads-The slowdown in certain sectors of the economy due to COVID-19 and
the initial stay-at-home order and subsequent phased reopening plans has
resulted in changes in retail load patterns. See "Customers and Demand" and
"Decoupling" in this Overview section and "Revenues" of the Results of
Operations section for more information related to COVID-19 impacts on retail
loads and Revenues, net.

Bad debt expense-The Company has responded to the hardships many customers are
facing and has taken steps to support its customers and communities, including
temporarily suspending disconnections and late fees during the crisis,
developing time payment arrangements, and partnering with local non-profits to
soften the impacts on small businesses and low-income residential customers.
PGE's bad debt expense was $15 million for the full-year 2020, compared to an
original $6 million forecast, subject to deferral. See "Administrative and
other" of the Results of Operations section for more information related to
COVID-19 impacts on bad debt expense, and see "Legislative and regulatory
developments" within this Overview section for more information regarding
regulatory deferrals of incremental costs associated with the COVID-19 pandemic.

Financial condition and liquidity-Global capital markets have experienced
significant volatility in response to COVID-19 and PGE continues to assess the
impact of this volatility on its liquidity position and capital investment
plans. The Company believes the combination of its revolver capacity, proceeds
of a $150 million, 364-day term loan, issued in April 2020, and proceeds from
$200 million and $230 million FMB issuances, in April and November 2020,
respectively, will continue to provide adequate liquidity for the Company's
operational needs. The Company continues to evaluate its five-year capital plan.
A detailed discussion of capital market and capital investment responses is
included in the Liquidity and Capital Resources section of this Item 7.

The COVID-19 pandemic did not have a material impact on PGE's financial condition and cash flows in 2020 and the Company continues to have sufficient liquidity to meet the Company's anticipated capital and operating


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requirements going forward. It is reasonably possible, however, that disruption
and volatility in the global capital markets may materially increase the cost of
capital.

Supply chain-The global nature of the COVID-19 pandemic has resulted in supply
chain disruptions and in some instances construction interruptions, although PGE
has not experienced significant supply chain disruptions or construction
interruptions to date. The Company's business continuity plans have included an
assessment of critical operational supply chain linkages and an assessment of
potential interruptions to its capital project execution. The Company will
continue to monitor supply chain issues, including possible force majeure
notices, for any material impacts to its operations.

Business continuity plans-In February 2020, as more information about the
potential impacts of COVID-19 became available, the Company activated its
business continuity plans. These plans are designed to ensure the safety of the
public and employees while the Company continues to provide critical service to
its customers. In addition to directing employees to work from home when
appropriate, the Company has implemented safeguards for employees who play
critical roles to ensure operational reliability and established protocols for
employees who interact directly with the public. The Company has enacted extra
physical security and cybersecurity measures to safeguard systems to serve
operational needs, including those of its remote workforce, and to ensure
uninterrupted service to customers. The Company will continue to evolve its
business continuity plans to follow guidance from the Centers for Disease
Control and the Oregon Health Authority. Although PGE has plans in place to
address workforce availability, including sequestration of key employees if
necessary, the Company has not experienced workforce availability issues to
date. Implementation of PGE's business continuity plans have not had a material
impact on PGE's results of operation.

Legislative and regulatory developments-The Company has analyzed available
relief for the economic effects of COVID-19 under the following:
•FERC Waiver-On June 30, 2020 the FERC issued a waiver that provides that, for
the 12-month period starting March 2020, jurisdictional utilities may apply an
alternative allowance for funds used during construction (AFDC) calculation
formula that excludes the actual outstanding short-term debt balance and
replaces it with the simple average of the actual 2019 short-term debt balance.
The purpose of the waiver is to allow relief from the detrimental impacts of
issuing short-term debt on the allowance for equity funds used during
construction. PGE adopted the waiver in the second quarter of 2020 and
retrospectively applied its provisions as of March 2020, resulting in a $1
million increase to AFDC. The Company continues to monitor for potential
extensions of the waiver beyond the original 12-month period.
•Coronavirus Aid, Relief, and Economic Security (CARES) Act-On March 27, 2020,
the U.S. Government enacted the CARES Act, which provides economic relief and
stimulus to support the national economy during the COVID-19 pandemic and
includes support for individuals, large corporations, small business, and health
care entities, among other affected groups. The Company has not experienced
direct material benefits from the CARES Act.
•COVID-19 Deferral-PGE filed an application for deferral of certain incremental
costs and lost revenue related to COVID-19 on March 20, 2020 with the OPUC. The
application requested the ability to defer incremental costs associated with the
COVID-19 pandemic but did not specify the precise scope of the deferral, or the
means by which PGE would recover deferred amounts. PGE, other utilities under
the OPUC's jurisdiction, intervenors, and OPUC staff held discussions regarding
the scope of costs incurred by utilities that may qualify for deferral under
Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on
Utility Customers. The result of such discussions was an Energy Term Sheet (Term
Sheet), which dictates costs in scope for deferral, but is silent to the timing
of recovery of such costs. On September 24, 2020, the Commission adopted OPUC
Staff's motion to execute stipulations incorporating the terms of the Term
Sheet. PGE's deferral application was approved by the Commission on October 20,
2020 with final stipulations for the Term Sheet approved on November 3, 2020. As
of December 31, 2020, PGE has deferred $8 million related to bad debt expense,
and $2 million for other incremental costs associated with COVID-19 under the
Term Sheet. All other incremental expenses will be recognized in the results of
operations, until a determination is made that cost recovery is probable.
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Amortization of any deferred costs will remain subject to OPUC review prior to
amortization and inclusion in customer prices. Although PGE expects its 2020
regulated ROE, after adjusting for certain energy trading losses, to exceed its
authorized ROE of 9.5%, PGE believes the full amount of the 2020 deferral is
probable of recovery as the Company's prudently incurred costs were in response
to the unique nature of the COVID-19 pandemic health emergency. The OPUC has
significant discretion in making the final determination of recovery and their
conclusion of overall prudence, including an earnings review, could result in a
portion, or all, of PGE's 2020 deferral being disallowed for recovery. Such
disallowance would be recognized as a charge to earnings.

Company Strategy



PGE is committed to continuing to achieve steady growth and returns as the
Company transforms to meet the challenges of climate change and an ever-evolving
energy grid. Customers, policy makers, and other stakeholders expect PGE to
reduce GHG emissions, keep the power grid reliable and secure, and ensure prices
are affordable, especially for the most vulnerable customers. The Company's
strategy strives to balance these interests. PGE plans to:
•Reduce GHG emissions associated with the power served to customers by 80% by
2030 (2010 baseline year), and setting an aspirational goal for zero GHG
emissions associated with the power served to customers by 2040;
•Electrify sectors of the economy like transportation and buildings that are
also transforming to reduce GHG emissions; and
•Perform as a business, driving improvements to work efficiency, safety of our
coworkers, and reliability of our systems and equipment all while adhering to
the Company's earnings per diluted share growth guidance of 4-6% on average.

Decarbonize the power supply-PGE partners with customers and local and state
governments to advance a clean energy future. PGE continues to leverage these
partnerships to pursue emission reductions using a diverse portfolio of clean
and renewable energy resources, and promote economy-wide emission reductions
through electrification and smart energy use to help the state meet its GHG
emission reduction goals. In addition to state greenhouse gas reduction goals,
PGE announced in 2020 a new company wide goal of achieving net zero GHG
emissions by 2040. PGE also announced a new goal to meet customer expectations
for clean energy, pledging to reduce GHG emissions associated with the power
served to customers by 80% by 2030 (2010 baseline year).

To reach these goals, PGE will focus on the following areas:



Customer Choice Programs-PGE's customers continue to express a commitment to
purchasing clean energy, as over 230,000 customers voluntarily participate in
PGE's Green Future Program, the largest renewable power program by participation
in the nation. In 2017, Oregon's most populous city, Portland, and most populous
county, Multnomah, each passed resolutions to achieve 100 percent clean and
renewable electricity by 2035 and 100 percent economy-wide clean and renewable
energy by 2050. Other jurisdictions in PGE's service area continue to consider
similar goals.

In response, the Company has implemented a new customer product option, the
Green Future Impact program, which allows for 100 MW of PGE-provided power
purchase agreements for renewable resources and up to 200 MW of
customer-provided renewable resources. Approved by the OPUC in the first quarter
2019, the program will provide business customers access to bundled renewable
attributes from those resources. Through this voluntary program, the Company
seeks to align sustainability goals, cost and risk management, reliable
integrated power, and a cleaner energy system.

Pursuant to the OPUC order approving the Green Future Impact tariff, program
subscribers remain cost of service customers, and pay both the cost of service
tariff price and the price under the renewable energy option tariff. This
structure is intended to avoid stranded costs and cost shifting.

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Carbon Legislation and Administrative Actions-In 2016, SB 1547 set a benchmark
for how much electricity must come from renewable sources like wind and solar
and requires the elimination of coal from Oregon utility customers' energy
supply no later than 2030 (subject to an exception that allows extension of this
date until 2035 for PGE's output from Colstrip).

Other provisions of the law include:
•An increase in RPS thresholds to 27% by 2025, 35% by 2030, 45% by 2035, and 50%
by 2040;
•A limitation on the life of Renewable Energy Credits (RECs) generated from
facilities that become operational after 2022 to five years, but continued
unlimited lifespan for all existing RECs and allowance for the generation of
additional unlimited RECs for a period of five years for projects online before
December 31, 2022; and
•An allowance for energy storage costs related to renewable energy in the
Company's RAC filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate
recovery of PGE's investment in the Colstrip facility from 2042 to 2030. In
January 2020, the owners of Colstrip Units 1 and 2 permanently retired those two
units. Although PGE has no direct ownership interest in Units 1 and 2, the
Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize
certain common facilities with Units 1 and 2.

Although PGE is currently scheduled to recover the costs of Colstrip by 2030,
some co-owners of Units 3 and 4 have sought approval to recover their costs
sooner in their respective jurisdictions. In its most recent depreciation study
filed with the OPUC in January 2021, PGE proposed to accelerate depreciation on
Colstrip generation assets through 2027. The Company continues to evaluate its
ongoing investment in Colstrip, including the possibility of earlier closure of
these facilities.

Any reduction in generation from Colstrip has the potential to provide capacity
on the Colstrip transmission facilities, which stretches from eastern Montana to
near the western end of the state to serve markets in the Pacific Northwest and
beyond. PGE has a 15% ownership interest in, and capacity on, the Colstrip
Transmission facilities. Renewable energy development in the state of Montana
could benefit from any excess transmission capacity that may become available.

As previously planned, in October 2020, PGE ceased coal-fired operation at Boardman and has begun decommissioning activities.



During the 2019 Oregon legislative session, House Bill (HB) 2020 was introduced,
which would have authorized a comprehensive cap and trade package in Oregon and
would have granted the OPUC direct authority to address climate change. Although
HB 2020 was not enacted in 2019, an amended version was reintroduced in the
35-day legislative session, which began in February 2020. This new proposal, SB
1530, was also a cap and trade package that included changes made to address
concerns raised by various parties. Prior to the legislative session, the OPUC
stated that it would continue to collaborate with the legislature and
stakeholders to make progress on climate change, noting that their authority was
limited to that of an economic regulator.

The short 2020 legislative session adjourned without action on SB 1530 and, as a
result, in March 2020, the Governor of Oregon issued an executive order
directing state agencies to seek to reduce and regulate GHG emissions. Many of
the direct agency actions are on an aggressive timeline with due dates in 2020
and 2021. As the Governor is limited by current statutory authority, the
executive order does not include a market-based mechanism as envisioned by the
cap and trade legislation introduced in the 2019 and 2020 legislative sessions.

Among other things, the executive order:
•Modified the statewide GHG emissions reduction goals to at least 45% below 1990
emission levels by 2035 and at least 80% below 1990 emission levels by 2050;
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•Directed state agencies to integrate climate change and the State's GHG
emissions reduction goals into their planning, budgets, investments, and
decisions to the extent allowed by law;
•Directed the OPUC to-
•determine whether utility portfolios and customer programs reduce risks and
costs to utility customers by making rapid progress towards reducing GHG
emissions consistent with Oregon's reduction goals;
•encourage electric companies to support transportation electrification
infrastructure that supports GHG emission reductions and zero emission vehicle
goals; and
•prioritize proceedings and activities that advance decarbonization in the
utility sector and exercise its broad statutory authority to reduce GHG
emissions, mitigate energy burden on utility customers, and ensure reliability
and resource adequacy;
•Directed the Oregon Department of Environmental Quality to adopt a program to
cap and reduce GHG emissions from large stationary sources, transportation
fuels, and other liquid or gaseous fuels including natural gas; and
•More than doubled the reduction goals of the state's Clean Fuels Program and
extended the program, from the previous rule that required a 10 percent
reduction in average carbon intensity of fuels from 2015 levels by 2025, to a 25
percent reduction below 2015 levels by 2035.

The Resource Planning Process-PGE's planning process includes working with
customers, stakeholders, and regulators to chart the course toward a clean,
affordable, and reliable energy future. This process includes consideration of
customer expectations and legislative mandates to move away from fossil fuel
generation and toward renewable sources of energy.

In May 2018, the Company issued a request for proposals seeking to procure
approximately 100 MWa of qualifying renewable resources. The prevailing bid was
Wheatridge, an energy facility in eastern Oregon that will combine 300 MW of
wind generation and 50 MW of solar generation with 30 MW of battery storage.

PGE now owns 100 MW of the wind resource, which was placed into service in the
fourth quarter of 2020 at a cost of $149 million and qualified for PTCs at the
100 percent level. Subsidiaries of NextEra Energy Resources, LLC own the balance
of the 300 MW wind resource, along with the solar and battery components, and
will sell their portion of the output to PGE under 30-year power purchase
agreements. PGE has the option to increase its ownership to include the entire
facility in 2032.

Construction of the solar and battery components is planned for 2021 and is also
expected to qualify for federal investment tax credits. PGE did not experience
any supply chain disruptions due to the COVID-19 pandemic related to the
construction of Wheatridge, and the solar and battery portions of the project
are proceeding as planned. PGE continues to work closely with the contractor to
actively monitor for supply chain issues. See "COVID-19 Impacts" within this
Overview section for further information on COVID-19.

On May 6, 2020, the OPUC issued an order that acknowledged the Company's 2019
IRP and the following Action Plan for PGE to undertake over the next four years
to acquire the resources identified:
•Customer actions-
•Seek to acquire all cost-effective energy efficiency; and
•Seek to acquire all cost-effective and reasonable distributed flexibility.
•Renewable actions-Conduct a Renewables Request for Proposals (RFP) seeking up
to approximately 150 MWa of new RPS-eligible resources that contribute to
meeting PGE's capacity needs by the end of 2024, with the following conditions,
among others:
•Resources must qualify for PTC or the federal Investment Tax Credit;
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•Resources must pass the cost-containment screen; and
•The value of RECs generated prior to 2030 must be returned to customers.
•Capacity actions-Pursue dispatchable capacity through the following concurrent
processes:
•Pursue cost-competitive, bilateral contract agreements for existing capacity in
the region; and
•Conduct an RFP for non-emitting dispatchable resources that contribute to
meeting PGE's capacity needs.

The order also requires that PGE consider resources in the Renewable and
Capacity RFPs in a co-optimized manner. PGE had requested authorization to
pursue up to approximately 700 MW of capacity contribution by 2025 from a
combination of renewables, existing resources, and new non-emitting dispatchable
capacity resources, such as energy storage. As PGE implements the Action Plan,
the Company will continue to evaluate present and ongoing resource needs and
timing of any related RFP in light of the economic disruption related to
COVID-19. PGE expects to issue an RFP for both renewable energy and capacity
resources.

PGE and Douglas County Public Utility District entered an agreement during 2020
to supply the Company additional capacity from facilities including the Wells
Hydroelectric Project, located on the Columbia River in central Washington. The
agreement also provides Douglas County PUD with PGE load management and
wholesale market sales services. With a start date of January 1, 2021, the
five-year agreement is expected to contribute between 100 and 160 MWs toward a
capacity need that PGE identified in its 2019 IRP. The agreement is a further
step toward the Company's stated goal of providing customers with a clean energy
future.

PGE filed an IRP Update with the OPUC in January 2021 seeking acknowledgement so
that it may incorporate the updated resource cost and value information in PURPA
QF avoided cost pricing. No changes were proposed to the 2019 IRP Action Plan in
the IRP Update. However, based on the updated capacity need forecast reflecting
the addition of the agreement with the Douglas County PUD and more sophisticated
modeling, the updated capacity need in 2025 is 511 MW.

Renewable Recovery Framework-As previously authorized by the OPUC, the RAC
allows PGE to recover prudently incurred costs of renewable resources through
filings made by April 1st each year. In the 2019 GRC Order, the OPUC authorized
the inclusion of prudent costs of energy storage projects associated with
renewables in future RAC filings to be made to the OPUC, under certain
conditions. Although no significant filings were made under the RAC during 2020,
the Company did submit a RAC filing for Wheatridge in the fourth quarter of
2019. On September 29, 2020, the OPUC issued an order in response to PGE's RAC
filing that stated PGE's decision to proceed with Wheatridge was prudent and
authorized cost recovery of, and return on, the facility in customer prices once
service to PGE's customers began, in the fourth quarter 2020.

Electrify other sectors of the economy-PGE is working toward an equitable, safe,
and clean energy future. Recent and future enhancements to the grid to enable a
seamless platform include:
•The use of electricity in more applications such as electric vehicles and heat
pumps;
•The integration of new, geographically-diverse energy markets;
•The deployment of new technologies like energy storage, communications
networks, automation and control systems for flexible loads, and distributed
generation;
•The development of connected neighborhood microgrids and smart communities; and
•The use of data and analytics to better predict demand and support energy
saving customer programs.

In July 2019, PGE's Board approved plans to construct an Integrated Operations
Center (IOC) as a key step to supporting this strategy, at an estimated total
cost of $200 million, excluding AFDC. The IOC will centralize mission-critical
operations, including those that are planned as part of the integrated grid
strategy. This secure, resilient facility will include infrastructure to support
and enhance grid operations and co-locate primary support
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functions. As of December 31, 2020, the Company has recorded $109 million, including AFDC, in construction work-in-progress related to the IOC.



The Company is also working to advance transportation electrification, with
projects aimed at improving accessibility to electric vehicle charging stations
and partnering with local mass transit agencies to transition to a greater use
of electric vehicles. In June 2019, the Oregon Legislature enacted SB 1044,
which establishes Oregon's zero emissions vehicle goals in statute at 250
thousand vehicle sales by 2025 and 90% of all vehicle sales by 2035. In
September 2019, PGE filed with the OPUC its first Transportation Electrification
plan, which considers current and planned activities, along with both existing
and potential system impacts, in relation to the State's carbon reduction goals.

In 2018, PGE filed an energy storage proposal that called for 39 MW of storage
to be developed over the next several years at various locations across the
grid. In August 2018, the OPUC issued an order that outlined an agreed approach
to the development of five energy storage projects by PGE with an expected
capital cost of approximately $45 million.

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

Wildfire-In 2020, Oregon experienced one of the most destructive wildfire
seasons on record, with over one million acres of land burned. PGE's wildfire
mitigation planning includes regular risk assessment. On September 7, 2020 PGE
proactively initiated a public safety power shutoff (PSPS) in a zone near Mt.
Hood that was identified as the region at highest risk of wildfire. In addition
to the PSPS region, PGE cut power to eight different high-risk fire areas. These
actions were coordinated with emergency responders and helped clear the path for
them to fight wildfires. During this time, PGE also established a community
resource center within the PSPS zone to help support the residents affected. The
Oregon Department of Forestry has opened an investigation into the causes of
wildfires in Clackamas County. The Company has received a subpoena and is fully
cooperating. The Company is not aware of any wildfires caused by PGE equipment.
PGE will incur costs to replace and rebuild PGE facilities damaged by the fires,
as well as addressing fire-damaged vegetation and other resulting debris and
hazards both in and outside of PGE's property and right-of-way. On October 20,
2020, the OPUC formally approved PGE's request for deferral of such costs. As of
December 31, 2020, PGE deferred $15 million in costs related to wildfire
response. PGE continues to assess the damage to its infrastructure and expects
regulatory recovery of prudently incurred restoration costs. Although PGE
expects its 2020 regulated ROE, after adjusting for certain energy trading
losses, to exceed its authorized ROE of 9.5%, PGE believes the full amount of
the 2020 deferral is probable of recovery as the Company's prudently incurred
costs were in response to the unique and unprecedented nature of the wildfire
events leading to the deferral. The OPUC has significant discretion in making
the final determination of recovery and their conclusion of overall prudence,
including an earnings review, could result in a portion, or all, of PGE's 2020
deferral being disallowed for recovery. Such disallowance would be recognized as
a charge to earnings.

Power Costs-Pursuant to the AUT process, PGE annually files an estimate of power
costs for the following year. As approved by the OPUC, the 2020 AUT included a
final increase in power costs for 2020, and a corresponding increase in annual
revenue requirement, of $27 million from 2019 levels, which were reflected in
customer prices effective January 1, 2020. See "Power Operations" within this
Overview section of Item 7 for more information regarding the PCAM.

Portland Harbor Environmental Remediation Account (PHERA) Mechanism-The EPA has
listed PGE as one of over one hundred PRPs related to the remediation of the
Portland Harbor Superfund site. As of December 31, 2020, significant
uncertainties still remained concerning the precise boundaries for clean-up, the
assignment of responsibility for clean-up costs, the final selection of a
proposed remedy by the EPA, and the method of allocation of costs amongst PRPs.
It is probable that PGE will share in a portion of these costs. In a Record of
Decision issued in 2017, the EPA outlined its selected remediation plan for
clean-up of the Portland Harbor site, which had an estimated total cost of $1.7
billion. However, the Company does not currently have sufficient information to
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reasonably estimate the amount, or range, of its potential costs for
investigation or remediation of Portland Harbor, although such costs could be
material to PGE's financial position. The impact of such costs to the Company's
results of operations is mitigated by the PHERA mechanism. As approved by the
OPUC, the Company's environmental recovery mechanism allows the Company to defer
and recover incurred environmental expenditures related to the Portland Harbor
Superfund Site through a combination of third-party proceeds, such as insurance
recoveries, and customer prices, as necessary. The mechanism established annual
prudency reviews of environmental expenditures and third-party proceeds, and
annual expenditures in excess of $6 million, excluding contingent liabilities,
are subject to an annual earnings test. Under the PHERA mechanism in 2020, PGE
incurred and deferred $6 million related to defense costs, net an estimated
refund of less than $1 million as a result of the regulated earnings test. PGE's
results of operations may be impacted to the extent such expenditures are deemed
imprudent by the OPUC or disallowed per the prescribed earnings test. For
further information regarding the PHERA mechanism, see "EPA Investigation of
Portland Harbor" in Note 19, Contingencies in the Notes to Consolidated
Financial Statements in Item 8.-"Financial Statements and Supplementary Data."

City of Portland Audit-In 2019, the city of Portland (the "City"), which is the
largest city within PGE's service territory, completed its audit of PGE's and
the City's mutual License Fees agreement for the 2012 through 2015 periods. The
preliminary claim by the City is that PGE improperly excluded certain items from
the calculation of gross revenues, which resulted in underpayment of franchise
taxes of $7 million, including interest and penalties. PGE disagreed with the
preliminary findings as they were not consistent with previous audit
conclusions, which found that the Company had appropriately calculated gross
revenues in determining franchise fees. In December 2020, PGE and the City
reached a settlement for less than $1 million that covered the audit periods
from 2012 to 2018.

Capital Project Deferral-In the second quarter of 2018, PGE placed into service
a new customer information system at a total cost of $152 million. In accordance
with agreements reached with stakeholders in the Company's 2019 GRC, the
Company's capital cost of the asset was included in rate base and customer
prices as of January 1, 2019.

Consistent with past regulatory precedent, in May 2018, the Company submitted an
application to the OPUC to defer the revenue requirement associated with this
new customer information system from the time the system went into service
through the end of 2018. As a result, PGE began deferring its incurred expenses,
primarily related to depreciation and amortization, of the new customer
information system once it was placed in service.

In 2017, the OPUC had opened docket UM 1909 to conduct an investigation of the
scope of its authority under Oregon law to allow the deferral of costs related
to capital investments for later inclusion in customer prices. In October 2018,
the OPUC issued Order 18-423 (1909 Order) concluding that the OPUC lacked
authority under Oregon law to allow deferrals of any costs related to capital
investments. In the 1909 Order, the OPUC acknowledged that this decision was
contrary to its past limited practice of allowing deferrals related to capital
investments and would require adjustments to its regulatory practices. The OPUC
directed its Staff to meet with the utilities and stakeholders to address the
full implications of this decision, and to propose recommendations needed to
implement this decision consistent with the OPUC's legal authority and the
public interest.

During 2018, PGE deferred a total of $12 million of expenses related to the
customer information system. However, the 1909 Order impacted the probability of
recovery of deferred expenses and, as such, the Company recorded a reserve for
the full amount of the costs related to the customer information system. The
reserve was established with an offsetting charge to the results of operations
in 2018.

In response to the 1909 Order, PGE and other utilities filed a motion for
reconsideration and clarification, which was denied. On April 19, 2019, PGE and
the other utilities filed a petition for judicial review of the 1909 Order with
the Oregon Court of Appeals, although the Court has indicated that the case
would be dismissed given the lack of recent action in the case.

On April 30, 2020, the OPUC issued a final order affirming its authority to defer all cost components related to a utility's capital projects, including both depreciation expense and the cost of financing capital projects. PGE


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believes that the costs incurred to date associated with the customer information system were prudently incurred; however, PGE intends to file to close the deferral proceeding related to the customer information system without further action at the OPUC.



Decoupling-The decoupling mechanism, authorized by the OPUC through 2022, is
intended to provide for recovery of margin lost as a result of a reduction in
electricity sales attributable to energy efficiency, customer-owned generation,
and conservation efforts by residential and certain commercial customers. The
mechanism provides for collection from (or refund to) customers if
weather-adjusted use per customer is less (or more) than that projected in the
Company's most recent general rate case.

The Company recorded an estimated refund of $15 million and a collection of $9
million from residential and commercial customers, respectively for the year
ended December 31, 2020, which resulted from variances between actual
weather-adjusted use per customer and that projected in the 2019 GRC. The
Company continues to see higher weather-adjusted use per customer from
residential customers that are spending more time at home and lower use per
customer from commercial customers that are adversely affected by COVID-19.

Collections under the decoupling mechanism are subject to an annual limitation
of 2% of revenues for each eligible customer class, based on the net prices in
effect for the applicable tariff schedule at the time of collection. For
collections recorded in 2020, the 2% limit will be applied to the net prices for
the applicable tariff schedules that will be in effect on January 1, 2022. The
Company reached its 2020 annual cap for collection from commercial customers
during the third quarter of 2020. No cap exists for any potential refunds under
the decoupling mechanism, thus increased demand from residential customers since
the onset of the COVID-19 pandemic has resulted in larger estimated refunds
under the decoupling mechanism, which have largely offset the revenue increases
that have resulted from higher residential demand. Any collection from customers
for the 2020 year is expected to occur over a one-year period, which would begin
January 1, 2022.

At December 31, 2019, PGE had recorded a total collection of $14 million that will be collected over a one-year period, which began January 1, 2021.



Corporate Activity Tax-In 2019, the state of Oregon enacted HB 3427, which
imposes a new gross receipts tax on companies with annual revenues in excess of
$1 million and applies to tax years beginning on or after January 1, 2020. The
tax applies to commercial activities sourced in Oregon, less a deduction for 35%
of the greater of "cost inputs" or "labor costs." The resulting amount is taxed
at 0.57%.

In January 2020, at PGE's request, the OPUC issued an order approving a tariff
and related deferral and balancing account to provide for an estimated recovery
of $7 million in customer prices in 2020. The Company will revisit the expected
tax consequences annually and revise the annual tariff accordingly. Pursuant to
the order, PGE started collections in customer prices February 1, 2020. For the
year ended December 31, 2020, PGE incurred $8 million under the tax.

Non-utility Asset Retirement Obligation (ARO)-PGE's Non-utility ARO represents
the liability that has been recognized for portions of unregulated properties
that are currently or previously leased to third parties and located adjacent to
PGE's T.W. Sullivan hydro generating facility. In 2020, PGE performed a
decommissioning study to update its ARO liability which resulted in a $21
million increase to non-utility property AROs. Additions in non-utility AROs
related to assets that are no longer in service are charged directly to
Depreciation and amortization on the consolidated statements of income in the
period in which the revisions are probable and reasonably estimable. As a part
of this study, the Company also established an additional ARO liability of $3
million related to utility properties that was charged to Depreciation and
amortization expense. PGE plans to pursue regulatory recovery for the utility
portion of the ARO update, however, as of December 31, 2020, no amounts have
been deferred as a regulatory asset. For further information regarding the
Company's AROs, see Note 8, Asset Retirement Obligations in the Notes to
Consolidated Financial Statements in Item 8.-"Financial Statements and
Supplementary Data."

Deferral of Boardman Revenue Requirement-In October 2020, intervenors filed a
deferral application with the OPUC that would require PGE to defer and refund
the revenue requirement associated with Boardman currently
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included in customer prices as established in the Company's last general rate
case. The application states a deferral is required for customers to adequately
capture the reduction in revenue requirement beginning on October 15, 2020, the
date Boardman ceased operations. PGE estimates this amount could be up to $14
million for the period ended December 31, 2020. As of December 31, 2020, PGE has
not recorded a regulatory liability pursuant to this deferral application as the
Company believes its current prices are just and reasonable in light of PGE's
continued substantial investments in utility plant. The costs of these
investments, which are not currently reflected in customer prices, more than
offsets the revenue requirement for Boardman. If the OPUC authorizes the
deferral, PGE would record a regulatory liability with a corresponding charge to
earnings.

2021 Storm- Beginning on February 11, 2021, an historic set of storms involving
heavy snow, winds, and ice impacted the United States, including PGE's service
territory. Significant damage across the State of Oregon led Oregon's Governor
to call a state of emergency on February 13, 2021. PGE's restoration efforts in
response to this historic set of storms are ongoing and the total costs of the
storm cannot be reasonably estimated, although such costs could be material to
its results of operations in 2021. Given the magnitude of the impacts to PGE's
transmission and distribution system, on February 15, 2021 PGE filed a deferral
application with the OPUC for potential recovery of restoration costs, however,
there is no assurance that such recovery would be granted by the OPUC.
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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. PGE also
participates in the CAISO western EIM, which allows the Company to, among other
things, integrate more renewable energy into the grid by better matching the
variable output of renewable resources. PGE also purchases natural gas in the
United States and Canada to fuel its generation portfolio and sells excess gas
back into the wholesale market.

The Company generates revenues and cash flows primarily from the sale and
distribution of electricity to its retail customers. The impact of seasonal
weather conditions on demand for electricity can cause the Company's revenues,
cash flows, and income from operations to fluctuate from period to period.
Historically, PGE has experienced its highest MWa deliveries and retail energy
sales during the winter heating season, although instances of peak deliveries
have increased during the summer months, generally resulting from air
conditioning demand. See "Seasonality" in the Customers and Revenues section in
Item 1.-"Business." for further information regarding seasonal fluctuations.
Retail customer price changes and customer usage patterns, which can be affected
by the economy, also have an effect on revenues. Wholesale power availability
and price, hydro and wind generation, and fuel costs for thermal and gas plants
can also affect income from operations.

Customers and Demand-The following tables present total energy deliveries and the average number of retail customers by customer type for 2020 and 2019.

% Increase/


 Energy deliveries (MWh in thousands)          2020               2019        (Decrease)
Retail:
   Residential                                 7,756              7,471             3.8  %

   Commercial (PGE sales only)                 6,222              6,653            (6.5)
     Direct Access                               633                665            (4.8)
   Total Commercial                            6,855              7,318            (6.3)

   Industrial (PGE sales only)                 3,446              3,181             8.3
     Direct Access                             1,486              1,490            (0.3)
   Total Industrial                            4,932              4,671             5.6

   Total (PGE sales only)                     17,424             17,305             0.7
     Total Direct Access                       2,119              2,155            (1.7)
   Total retail energy deliveries             19,543             19,460             0.4  %
Wholesale energy deliveries                    5,794              4,669            24.1
   Total energy deliveries                    25,337             24,129             5.0  %



Average number of retail customers                2020                     2019              % Increase
Residential                                791,119        88  %     779,673        88  %          1.5  %
Commercial                                 110,290        12        109,521        12             0.7
Industrial                                     194         -            193         -             0.5
Direct access                                  634         -            632         -             0.3
Total                                      902,237       100  %     890,019       100  %          1.4  %



In 2020, retail energy deliveries increased 0.4% from 2019. While results for
the first quarter largely reflected conditions prior to the COVID-19 pandemic,
the remainder of the year was influenced by customer behavioral response to the
pandemic.
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On March 23, 2020, the Governor of Oregon issued an order directing residents to
stay at home except for essential activity and mandating closure of businesses
for which close personal contact would be difficult or impossible to avoid. The
Company saw a shift in retail demand in response, beginning with the second
quarter of 2020. In particular, residential loads increased as a larger
percentage of the population spent more time at home, whether working from home,
providing child-care due to school closures, or lacking employment as commercial
activity slowed. Conversely, commercial energy deliveries declined as many
businesses were disrupted in an attempt to maintain social distancing or have
closed as a result of the lack of business as residents followed directives from
state and federal authorities. Although the industrial class as a whole
experienced an increase in energy deliveries for 2020, this was due primarily to
continued growth in the high-tech and digital services sectors, which saw lesser
impacts from noted closures than other sectors.

Residential energy deliveries, which are most sensitive to fluctuations in
temperatures, were 3.8% higher in 2020 than 2019, due to a 2.3% increase in
average usage per customer and a 1.5% increase in the average number of
customers. Residential deliveries, down 6% in the first quarter driven by mild
temperatures, were up 9% in the second quarter of 2020 due largely to the impact
of the COVID-19 pandemic and have remained strong through the balance of the
year.

Commercial energy deliveries declined 6.3% overall with widespread decreases
across PGE's customer base led by several sectors most impacted by COVID-19
related closures and economic conditions, including: government and education;
offices, finance, insurance, and real estate; and restaurants and lodging.

The 5.6% increase during 2020 in industrial energy deliveries is due to
continued strength in the high-tech manufacturing sector as well as a full-year
of demand from a large paper facility that reopened during 2019, after having
closed in late 2017.

In 2020, the Company's service territory experienced warmer temperatures during
the heating season than in 2019, indicating lower demand for heating, the effect
of which was partially offset by having slightly warmer temperatures during the
summer cooling season and increased demand for cooling.

Total heating degree-days, an indication of electricity use for heating, in 2020
were 7% below the 15-year average and down 8% from total heating degree-days in
2019. Total cooling degree-days, a similar indication of the extent to which
customers are likely to have used electricity for cooling, in 2020, exceeded the
15-year average by 12% and were 6% above the 2019 total. The following table
presents the number of heating and cooling degree-days in 2020 and 2019, along
with the current 15-year averages, reflecting that weather had a considerable
influence on comparative energy deliveries:

                                                        Heating Degree-Days                                                    Cooling Degree-Days
                                        2020                   2019              15-Year Average                 2020                   2019             15-Year Average
1st quarter                                1,761                 1,992                1,848                              -                   -                    -
2nd quarter                                  554                   467                  636                             99                 102                   89
3rd quarter                                   47                    83                   78                            492                 462                  447
4th quarter                                1,474                 1,623                1,583                              9                   -                    2
Total                                      3,836                 4,165                4,145                            600                 564                  538
Increase (decrease) from the
15-year average                               (7) %                  -  %                                               12  %                5  %



On a weather-adjusted basis, total retail deliveries increased 1.5% from 2019.
The increase was driven by 6.3% growth in residential deliveries and 5.6% growth
in industrial energy deliveries, which were somewhat offset by a decrease in
commercial energy deliveries of 6.0%. Retail energy deliveries for 2021 will
continue to be impacted by COVID-19 related behavioral changes. PGE projects
that retail energy deliveries for 2021 will be approximately
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1.0% - 1.5% above 2020 weather-adjusted levels, reflecting strength in industrial deliveries, and impacts associated with COVID-19 early in the year, and unwinding of such impacts later in the year.



ESSs supplied Direct Access customers with energy representing 11% of the
Company's total retail energy deliveries during 2020 and 2019. The maximum
retail load allowed to be supplied under the fixed three-year and minimum
five-year opt-out programs represent 13% of the Company's total retail energy
deliveries for 2020, and 2019. With the adoption of the New Large Load Direct
Access program in 2020, as much as 19% of the Company's energy deliveries could
have been supplied by ESSs.

Energy efficiency and conservation efforts by retail customers influence demand,
although the financial effects of such efforts by residential and certain
commercial customers are mitigated by the decoupling mechanism, which is
intended to provide for recovery of margin lost as a result of a reduction in
electricity sales attributable to energy efficiency and conservation efforts.
The mechanism provides for collection from (or refund to) customers if
weather-adjusted use per customer is less (or more) than the projected baseline
set in the Company's most recent approved general rate case. See "Decoupling" in
this Overview section of Item 7, for further information on the decoupling
mechanism.

Power Operations-PGE utilizes a combination of its own generating resources and
wholesale market transactions to meet the energy needs of its retail customers.
Based on numerous factors, including plant availability, customer demand, river
flows, wind conditions, and current wholesale prices, the Company continuously
makes economic dispatch decisions in an effort to obtain reasonably-priced power
for its retail customers. PGE also purchases wholesale natural gas in the United
States and Canada to fuel its generating portfolio and sells excess gas back
into the wholesale market. As a result, the amount of power generated and
purchased in the wholesale market to meet the Company's retail load requirement
can vary from period to period and impacts NVPC and income from operations.

The following table provides information regarding the performance of the Company's generation portfolio.


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

                                          2020             2019                           2020           2019                        2020          2019

Thermal:
Natural gas                                      92  %         92  %                          74  %          86  %                       43  %         45  %
Coal (3)                                         99            87                             83            104                          17            24

Wind                                             94            96                            117             90                          11             9
Hydro                                            86            93                             71             81                           7             8


(1)Plant availability represents the percentage of the year plants were
available for operations, which is impacted by planned maintenance and forced,
or unplanned, outages.
(2)Projected levels of energy are included as part of PGE's AUT. Such
projections establish the power cost component of retail prices for the
following calendar year. Any shortfall is generally replaced with power from
higher cost sources, while any excess generally displaces power from higher cost
sources.
(3)Plant availability excludes Colstrip, which PGE does not operate. Colstrip
availability was 74% in 2020, compared with 85% in 2019. Boardman ceased
coal-fired generation on October 15, 2020.

Energy received from PGE-owned and jointly-owned thermal plants decreased 12% in
2020 compared to 2019, primarily as a result of a 27% reduction in generation
from coal-fired generation, which produced only 13% of the Company's total
system load in 2020. Energy expected to be received from thermal resources is
projected annually in the AUT based on forecast market prices, variable costs to
run the plant, and the constraints of the plant. PGE's thermal generating plants
require varying levels of annual maintenance, which is generally performed
during the second quarter of the year.

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Total energy received from hydroelectric generation sources, both PGE-owned
generation and purchased, increased 12% in 2020 compared to 2019. While energy
received from mid-Columbia hydroelectric projects increased 46% in 2020, the
energy generated by the Company-owned facilities decreased 14%. Energy expected
to be received from hydroelectric resources is projected annually in the AUT
based on a modified hydro study, which utilizes 80 years of historical stream
flow data. See "Purchased power and fuel" in the Results of Operations section
in this Item 7, for further detail on regional hydro results.

Energy received from PGE-owned wind resources and under contracts increased 28%
in 2020 compared to 2019, due to more favorable wind conditions in 2020 and the
addition of Wheatridge during the fourth quarter 2020. Energy expected to be
received from Biglow Canyon and Tucannon River is projected annually in the AUT
based on historical generation. Wind generation forecasts are developed using a
5-year rolling average of historical wind levels or forecast studies when
historical data is not available. As a result of the generation increase, a
larger amount of PTCs were produced in 2020 than in 2019 and exceeded what was
contemplated in the Company's prices.

For Wheatridge, wind generation studies were used to develop NVPC cost
forecasts, which were included in the RAC filing for the facility, and included
in customer prices when the facility went into service. The RAC tariff included
NVPC in 2020 along with all other aspects of the revenue requirement. Beginning
January 1, 2021, the NVPCs were included in the Company's AUT, although the
other aspects of the RAC tariff will remain in effect until they are included in
customer prices as a result of a future general rate case.

Under the PCAM, PGE may share with customers a portion of cost variances
associated with NVPC. Customer prices can be adjusted annually to absorb a
portion of the difference between the forecasted NVPC included in customer
prices (baseline NVPC) and actual NVPC for the year, if such differences exceed
a prescribed "deadband" limit, which ranges from $15 million below to $30
million above baseline NVPC. To the extent actual NVPC, subject to certain
adjustments, is outside the deadband range, the PCAM provides for 90% of the
excess variance to be collected from, or refunded to, customers. Pursuant to a
regulated earnings test, a refund will occur only to the extent that it results
in PGE's actual regulated return on equity (ROE) for the given year being no
less than 1% above the Company's latest authorized ROE, while a collection will
occur only to the extent that it results in PGE's actual regulated ROE for that
year being no greater than 1% below the Company's authorized ROE. The following
is a summary of the results of the Company's PCAM as calculated for regulatory
purposes for 2020, and 2019:

•For 2020, actual NVPC, excluding certain trading losses totaling $127 million,
was below baseline NVPC by $13 million, which was within the established
deadband range, so no estimated refund to customers was recorded as of December
31, 2020. A final determination regarding the 2020 PCAM results will be made by
the OPUC through a public filing and review in 2021. If actual NVPC for 2020
included the certain trading losses, it would have been $114 million above the
baseline. See "Energy Trading" in the Overview section of this Item 7. for
further information regarding certain trading losses.

•For 2019, actual NVPC was above baseline NVPC by $5 million, which was within
the established deadband range. Accordingly, no estimated refund to customers
was recorded as of December 31, 2019. A final determination regarding the 2019
PCAM results was made by the OPUC through a public filing and review in 2020,
which confirmed no refund to customers pursuant to the PCAM for 2019.

The AUT filing, which serves to reset the baseline NVPC for PCAM purposes, indicated that a $27 million increase was expected in 2020 over 2019. The 2021 AUT anticipates a $79 million increase in NVPCs that will be recovered in customer prices beginning January 1, 2021.

Results of Operations

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



PGE defines Gross margin as Total revenues less Purchased power and fuel. Gross
margin is considered a non-GAAP measure as it excludes depreciation and
amortization and other operation and maintenance expenses. The presentation of
Gross margin is intended to supplement an understanding of PGE's operating
performance in
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relation to changes in customer prices, fuel costs, impacts of weather, customer counts and usage patterns, and impact from regulatory mechanisms such as decoupling. The Company's definition of Gross margin may be different from similar terms used by other companies and may not be comparable to their measures.



The results of operations are as follows for the years presented (dollars in
millions):
                                                                       Years Ended December 31,
                                                                         2020                2019              % Increase
                                                                        Amount              Amount             (Decrease)
Total revenues (1)                                                 $       2,145          $ 2,123                        1  %
Purchased power and fuel (1)                                                 708              614                       15
Gross margin                                                               1,437            1,509                       (5)
Other operating expenses:
Generation, transmission and distribution                                    293              323                       (9)

Administrative and other                                                     283              290                       (2)
Depreciation and amortization                                                454              409                       11
Taxes other than income taxes                                                138              134                        3
Total other operating expenses                                             1,168            1,156                        1
Income from operations                                                       269              353                      (24)
Interest expense, net (2)                                                    136              128                        6
Other income:
Allowance for equity funds used during construction                           16               10                       60
Miscellaneous income, net                                                      6                6                        -
Other income, net                                                             22               16                       38
Income before income taxes                                                   155              241                      (36)
Income tax (benefit) expense                                                   -               27                     (100)
Net income                                                         $         155          $   214                      (28) %

(1) Gross margin agrees to Total revenues less Purchased power and fuel as reported on PGE's Consolidated Statements of Income. (2) Includes an allowance for borrowed funds used during construction of $8 million in 2020 and $5 million in 2019.


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2020 Compared to 2019

Net income - The following items contributed to the change in Net income for the year ended December 31, 2020 compared to the year ended December 31, 2019 (dollars in millions):



Year ended December 31, 2019                                              $

214

Purchased power and fuel expense related to certain trading losses*

(127)

Purchased power and fuel expense, excluding certain trading losses* 

            43

Other operating revenues primarily from the resale of excess natural gas

(17)


used for fuel in 2019 that did not recur in 2020
Average retail price predominately due to increase under the AUT for NVPC              37
Retail deliveries, net of decoupling deferral

(11)


Wholesale revenues driven by lower average sale prices                                 (8)

Late fee revenue due largely to COVID-19 related curtailments                          (6)

Generation, transmission and distribution expenses driven by lower plant 

            30

maintenance

Administrative and general expenses due largely to lower wages and 

             9

benefits


Non-utility ARO due to revised estimates

(21)

Depreciation and amortization resulting largely from capital additions

(11)


Income taxes resulting primarily from lower pre-tax income                             27
Other                                                                                  (4)
Year ended December 31, 2020                                                          155
Change in Net income                                                      $           (59)

*See "Energy Trading" in the Overview section of this Item 7.-"Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information regarding certain trading losses.



Total revenues consist of the following for the years presented (in millions):
                                                             2020             2019          % Increase (Decrease)
Retail: (1)
Residential                                               $ 1,030          $   981                           5  %
Commercial                                                    616              636                          (3)
Industrial                                                    218              196                          11
Direct Access                                                  46               44                           5
Subtotal                                                    1,910            1,857                           3
Alternative revenue programs, net of amortization              (6)               2                        (400)
Other accrued revenues, net (2)                                28               22                          27
Total retail revenues                                       1,932            1,881                           3
Wholesale revenues                                            162              170                          (5)
Other operating revenues                                       51               72                         (29)
Total revenues                                            $ 2,145          $ 2,123                           1  %

(1) Includes both revenues from customers who purchase their energy supplies from the Company

and revenues from the delivery of energy to those customers that purchase their energy from

ESSs. Commercial revenues from ESS customers were $18 million for 2020 and 2019. Industrial

revenues from ESS customers were $28 million and $26 million for 2020 and 2019,

respectively.

(2) Amounts for the years ended December 31, 2020 and 2019 are primarily comprised of $24

million and $23 million of amortization, respectively, including interest, related to the


       net tax benefits due to the change in corporate tax rate under the TCJA.


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Total retail revenues-The following items contributed to the increase in Total
retail revenues for the year ended December 31, 2020 compared to the year ended
December 31, 2019 (dollars in millions):

Year ended December 31, 2019                                                  $       1,881
Retail energy deliveries driven by higher industrial demand, the impact of
COVID-19 resulting in higher residential demand, and the negative effects of
weather                                                                                   8

Average price of energy deliveries due primarily to the AUT and the variation in usage among customer classes resulting from COVID-19

                                  27

Combination of various supplemental tariffs and adjustments, the largest of which were $11 million that pertains to the demand response pilot programs, $8 million related to Boardman decommissioning, and $7 million for the Oregon Commercial Activities Tax

                                                                24

Alternative revenue programs related to the decoupling mechanism deferrals due to increased residential use per customer resulting from COVID-19

                   (19)

Amortization of prior year decoupling deferrals into customer prices 

              11
Year ended December 31, 2020

1,932


Change in Total retail revenues

$ 51





Wholesale revenues result from sales of electricity to utilities and power
marketers made in the Company's efforts to secure reasonably priced power for
its retail customers, manage risk, and administer its current long-term
wholesale contracts. Such sales can vary significantly from year to year as a
result of economic conditions, power and fuel prices, hydro and wind
availability, and customer demand.

In 2020, an $8 million, or 5%, decrease from 2019 in wholesale revenues resulted
from a $49 million decrease from a 23% decrease in average prices received when
the Company sold power into the wholesale market, partially offset by a $41
million increase related to a 24% increase in wholesale sales volume.
Other operating revenues decreased $21 million, or 29%, in 2020 from 2019,
primarily as a result of a $17 million decrease predominately resulting from
market conditions that provided less revenue from the resale of natural gas back
into the wholesale market in excess of amounts needed for the Company's
generation portfolio. Natural gas prices were considerably higher in the first
quarter of 2019 as a result of a supply pipeline disruption in the region.
Milder than average winter temperatures in North America in 2020 resulted in an
oversupply of natural gas and lower prices. In addition, a $6 million decrease
occurred due to the curtailment of late fees as a result of the COVID-19
pandemic.


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

The following items contributed to the increase in Purchased power and fuel for
the year ended December 31, 2020 compared to the year ended December 31, 2019
(dollars in millions, except for average variable power cost per MWh):

                  Year ended December 31, 2019            $   614
                  Average variable power cost per MWh          62
                  Total system load                            32
                  Year ended December 31, 2020            $   708
                  Change in Purchased power and fuel      $    94

                  Average variable power cost per MWh:
                  Year ended December 31, 2019            $ 26.62
                  Year ended December 31, 2020            $ 29.14

                  Total system load (MWh in thousands):
                  Year ended December 31, 2019               23,085
                  Year ended December 31, 2020               24,286



For the year ended December 31, 2020, the $62 million increase related to the
change in average variable power cost per MWh, was primarily driven by an 8%
increase in the average cost for purchased power, partially offset by a 14%
decrease on the average cost for the Company's own generation. The increase in
the cost of purchased power was driven by realized losses of $127 million
related to a portion of energy trading positions in PGE's energy portfolio. See
"Energy Trading" in the Overview section of this Item 7., for more details. The
$32 million increase related to total system load was primarily due to a 35%
increase in purchased power, driven by economic dispatch decisions based on
lower gas prices and surplus hydro in the region.

PGE's sources of energy, total system load, and retail load requirement for the years presented are as follows:


                                                         Years Ended

December 31,


                                                       2020                            2019
Sources of energy (MWh in thousands):
Generation:
Thermal:
Natural gas                                              8,029        33  %      8,342        36  %
Coal                                                     3,232        13         4,416        19
Total thermal                                           11,261        46        12,758        55
Hydro                                                    1,204         5         1,407         6
Wind                                                     2,111         9         1,706         8
Total generation                                        14,576        60        15,871        69
Purchased power:
Term contracts                                           7,741        32         5,882        25
Hydro                                                    1,535         6         1,048         5
Wind                                                       434         2           284         1

Total purchased power                                    9,710        40         7,214        31
Total system load                                       24,286       100  %     23,085       100  %
Less: wholesale sales                                   (5,794)                 (4,669)
Retail load requirement                                 18,492                  18,416


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The following table presents the actual April-to-September 2020 and 2019 runoff at particular points of major rivers relevant to PGE's hydro resources:


                                                                 Runoff as

a Percent of 30-year Average


                                                                      2020                     2019
                           Location                                  Actual                   Actual
Columbia River at The Dalles, Oregon                                       104  %                    94  %
Mid-Columbia River at Grand Coulee, Washington                             109                       87
Clackamas River at Estacada, Oregon                                         75                      114
Deschutes River at Moody, Oregon                                            86                      111



Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale
revenues, increased $102 million in 2020 compared with 2019. The increase
attributable to changes in Purchased power and fuel expense was the result of a
9% increase in the average variable power cost per MWh and a 5% increase in
total system load. In addition, wholesale energy deliveries decreased $8 million
from the net of 23% lower average price per MWh sold, partially offset by a 24%
increase in the volume of wholesale energy deliveries.

The following items contributed to the increase in Actual NVPC for the year
ended December 31, 2020 compared to the year ended December 31, 2019 (in
millions):

                     Year ended December 31, 2019       $ 444
                     Purchased power and fuel expense      94
                     Wholesale revenues                     8
                     Year ended December 31, 2020         546
                     Change in NVPC                     $ 102

For further information regarding NVPC in relation to the PCAM, see "Power Operations" in the Overview section of this Item 7.

Generation, transmission, and distribution



The following items contributed to the $30 million or 9% decrease in Generation,
transmission and distribution for the year ended December 31, 2020 compared to
the year ended December 31, 2019 (in millions):

Year ended December 31, 2019                                                $         323
Decrease primarily due to lower maintenance expense as the result of

(20)

reduced run hours and lower long-term service agreement costs at some of the Company's generation facilities Lower utilization of contract labor and higher capitalization rates

                    (8)
Miscellaneous expenses                                                                 (2)
Year ended December 31, 2020

293


Change in Generation, transmission and distribution

$ (30)





For the year ended December 31, 2020, PGE deferred $15 million of incremental
costs related to wildfires in PGE's service territory. See "Wildfires" within
"Perform as a business" under "Company Strategy" in the Overview section of this
Item 7., for more information.


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Administrative and other

The following items contributed to the $7 million or 2% decrease in Administrative and other for the year ended December 31, 2020 compared to the year ended December 31, 2019 (in millions):



                    Year ended December 31, 2019         $ 290
                    Wage and benefits expenses             (12)
                      Bad debt expense                       5

                    Year ended December 31, 2020           283
                    Change in Administrative and other   $  (7)

As of December 31, 2020, PGE has deferred $8 million of bad debt related to incremental expense incurred related to COVID-19 as part of the OPUC's Energy Term Sheet. See the "Overview" section of this Item 7., for more information.

Depreciation and amortization

The following items contributed to the $45 million or 11%, increase in Depreciation and amortization for the year ended December 31, 2020 compared to year ended December 31, 2019 (in millions):



       Year ended December 31, 2019                                   $ 409
       ARO revisions                                                     24
       Activity related to regulatory programs (offset in revenues)      13
       Capital additions                                                  8

       Year ended December 31, 2020                                     454
       Change in Depreciation and amortization                        $  45

See "Non-utility Asset Retirement Obligation Overview" within "Perform as a business" under "Company Strategy" in the Overview section of this Item 7., for more information regarding revisions made to non-utility AROs.

Taxes other than income taxes expense increased $4 million, or 3%, in 2020 compared with 2019, primarily due to higher Oregon property taxes.



Interest expense increased $8 million, or 6%, in 2020 compared with 2019 due to
higher average balances of outstanding debt as well as increased interest on
finance leases.

Other income, net increased $6 million, or 38%, in 2020 compared to 2019, with the difference due to higher AFDC equity driven by higher construction work-in-progress balances in 2020.

Income tax expense decreased $27 million, or 100%, in 2020 compared to 2019 primarily due to lower pre-tax income in 2020, partially offset by higher expense from the Oregon Corporate Activity tax which took effect on January 1, 2020.



2019 Compared to 2018

For a comparison of the Company's results of operations for the fiscal year ended December 31, 2019 to the year ended December 31, 2018, see Item 7.-" Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 14, 2020.


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Liquidity and Capital Resources



Discussions, forward-looking statements, and projections in this section, and
similar statements in other parts of this Annual Report on Form 10-K, are
subject to PGE's assumptions regarding the availability and cost of capital. See
"Capital and credit market conditions could adversely affect the Company's
access to capital, cost of capital, and ability to execute its strategic plan as
currently envisioned." in Item 1A.-"Risk Factors," for further information.

Capital Requirements

The following table presents actual capital expenditures and debt maturities for 2020 and projected capital expenditures and future debt maturities for 2021 through 2025 (in millions, excluding AFDC):


                                                         Years Ending December 31,
                                        2020       2021       2022       2023       2024       2025
Ongoing capital expenditures*          $ 568      $ 555      $ 550      $ 550      $ 550      $ 550
Integrated Operations Center              77        100          -          -          -          -
Wheatridge Renewable Energy Facility     129          -          -          -          -          -
Total capital expenditures             $ 774      $ 655      $ 550      $ 550      $ 550      $ 550

Long-term debt maturities              $   -      $ 160      $   -      $   -      $  80      $   -

* Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connects. Includes preliminary engineering and removal costs.



During 2020, PGE funded its capital expenditures through a combination of cash
from operations in the amount of $567 million, net proceeds from the issuance of
PCRBs and FMBs in the total amount of $451 million, and net short-term debt
issuances in the amount of $150 million. Capital expenditures in 2021 are
expected to be $655 million. PGE plans to fund the 2021 capital expenditures and
long-term debt maturities with cash from operations during 2021, which is
expected to range from $600 million to $650 million, the issuance of debt
securities of up to $300 million, and the issuance of commercial paper, as
needed. The actual timing and amount of any other issuances of debt or
commercial paper will be dependent upon the timing and amount of capital
expenditures. For a discussion concerning PGE's ability to fund its future
capital requirements, see "Debt and Equity Financings" in the Liquidity and
Capital Resources section of this Item 7.

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, 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.


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

                                                       Years Ended December 31,
                                                           2020                  2019
Cash and cash equivalents, beginning of year   $          30                    $ 119
Net cash provided by (used in):
Operating activities                                     567                      546
Investing activities                                    (787)                    (604)
Financing activities                                     447                      (31)
Net change in cash and cash equivalents                  227

(89)


Cash and cash equivalents, end of year         $         257                    $  30



2020 Compared to 2019

Cash Flows from Operating Activities-Cash flows from operating activities are
generally determined by the amount and timing of cash received from customers
and payments made to vendors, as well as the nature and amount of non-cash
items, including depreciation and amortization, deferred income taxes, and
pension and other postretirement benefit costs included in net income during a
given period. The $21 million increase in cash flows from operating activities
in 2020 compared to 2019 is due to:

•$59 million reduction in Net income in 2020;
•$63 million increase related to additional contributions to the pension and
other postretirement benefit plans in 2019 that did not recur in 2020;
•$45 million increase in Depreciation and amortization primarily due to higher
average plant balances and revision to non-utility AROs in 2020. See the
Overview section of this Item 7., for more information regarding revisions made
to non-utility AROs;
•$42 million increase for Accounts payable and other accrued liabilities
primarily due to the timing of payments to vendors;
•$29 million increase in Other working capital, net primarily due to the use of
materials and supplies and fuel inventory in the course of business; partially
offset by
•$54 million decrease as a result of changes in Accounts receivable and Unbilled
revenue;
•$29 million decrease related to Deferred income taxes;
•$9 million decrease related to cash settlements for ARO liabilities; and
•$7 million decrease related to other miscellaneous items.

For additional information regarding changes in Net income, see the Results of Operations section in this Item 7.



Cash provided by operations includes the recovery in customer prices of non-cash
charges for depreciation and amortization. The Company estimates that such
charges in 2021 will range from $410 million to $430 million. Combined with all
other sources, cash provided by operations in 2021 is estimated to range from
$600 million to $650 million.

Cash Flows from Investing Activities-Cash flows used in investing activities
consist primarily of capital expenditures related to new construction and
improvements to PGE's distribution, transmission, and generation facilities. The
$183 million increase in net cash used in investing activities in 2020 compared
with 2019 is primarily due to the construction of Wheatridge and the IOC.
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The Company plans for $655 million of capital expenditures in 2021 related to
upgrades to and replacement of generation, transmission, and distribution
infrastructure. PGE plans to fund the 2021 capital expenditures with cash from
operations during 2021, as discussed above, as well as with the issuance of
short- and long-term debt securities. For additional information, see "Capital
Requirements" and "Debt and Equity Financings" in the Liquidity and Capital
Resources section of this Item 7.

Cash Flows from Financing Activities-Financing activities provide supplemental
cash for both day-to-day operations and capital requirements as needed. During
2020, cash provided by financing activities consisted primarily of the issuance
of $430 million of FMBs and $119 million of PCRBs, less the remarketing of $98
million of PCRBs. In addition, the Company issued a $150 million short-term loan
and paid dividends in the amount of $140 million.

2019 Compared to 2018



For a comparison of liquidity and capital resources and the Company's cash flow
activities for the fiscal year ended December 31, 2019 and 2018, see Item
7.-"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report on Form 10-K for the year ended
December 31, 2019, which was filed with the SEC on February 14, 2020.

Credit Ratings and Debt Covenants

PGE's secured and unsecured debt is rated investment grade by Moody's and S&P, with current credit ratings and outlook as follows:


                          Moody's         S&P
First Mortgage Bonds        A1             A
Senior unsecured debt       A3            BBB+
Commercial paper            P-2           A-2
Outlook                   Stable         Stable



In the event Moody's and/or S&P reduce their credit rating on PGE's unsecured
debt below investment grade, the Company could be subject to requests by certain
of its wholesale, commodity, and transmission counterparties to post additional
performance assurance collateral in connection with its price risk management
activities. The performance assurance collateral can be in the form of cash
deposits or letters of credit, depending on the terms of the underlying
agreements, and are based on the contract terms and commodity prices and can
vary from period to period. Cash deposits provided as collateral are classified
as Margin deposits in PGE's consolidated balance sheets, while any letters of
credit issued are not reflected in the Company's consolidated balance sheets.

As of December 31, 2020, PGE had posted $20 million of collateral with these
counterparties, consisting of $8 million in cash and $12 million in bank letters
of credit. Based on the Company's energy portfolio, estimates of energy market
prices, and the level of collateral outstanding as of December 31, 2020, the
amount of additional collateral that could be requested upon a single agency
downgrade to below investment grade is $32 million and decreases to zero by
December 31, 2021. The amount of additional collateral that could be requested
upon a dual agency downgrade to below investment grade is $122 million and
decreases to $79 million by December 31, 2021 and $72 million by December 31,
2022.

PGE's financing arrangements do not contain ratings triggers that would result
in the acceleration of required interest and principal payments in the event of
a ratings downgrade. However, the cost of borrowing and issuing letters of
credit under the credit facilities would increase.

The Indenture securing PGE's outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of


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T a b l e o f C o n t e n t s



Mortgage and Deed of Trust securing the bonds. PGE estimates that on
December 31, 2020, under the most restrictive issuance test in the Indenture of
Mortgage and Deed of Trust, the Company could have issued up to $695 million of
additional FMBs. Any issuances of FMBs would be subject to market conditions and
amounts could be further limited by regulatory authorizations or by covenants
and tests contained in other financing agreements. PGE also has the ability to
release property from the lien of the Indenture of Mortgage and Deed of Trust
under certain circumstances, including bond credits, deposits of cash, or
certain sales, exchanges, or other dispositions of property.

PGE's credit facilities contain customary covenants and credit provisions,
including a requirement that limits consolidated indebtedness, as defined in the
credit agreements, to 65.0% of total capitalization (debt to total capital
ratio). As of December 31, 2020, the Company's debt to total capital ratio, as
calculated under the credit agreements, was 56.4%.

Debt and Equity Financings



PGE's ability to secure sufficient short- and long-term capital at a reasonable
cost is determined by its financial performance and outlook, its credit ratings,
its capital expenditure requirements, alternatives available to investors,
market conditions, and other factors, such as the significant volatility in the
capital markets in response to COVID-19. Management believes that the
availability of its revolving credit facility, the expected ability to issue
short- and long-term debt and equity securities, and cash expected to be
generated from operations provide sufficient cash flow and liquidity to meet the
Company's anticipated capital and operating requirements for the foreseeable
future.

Short-term Debt-Pursuant to an order issued by the FERC on January 16, 2020, PGE
has authorization to issue short-term debt up to a total of $900 million through
February 6, 2022. The following table shows available liquidity as of December
31, 2020 (in millions):
                                                        December 31, 2020
                                            Capacity       Outstanding       Available

         Revolving credit facility (1)    $   500         $          -      $      500
         Letters of credit (2)                220                   60             160
         Total credit                     $   720         $         60      $      660
         Cash and cash equivalents                                                 257
         Total liquidity                                                    $      917


(1)Scheduled to expire November 2023.
(2)PGE has four letter of credit facilities under which the Company can request
letters of credit for an original term not to exceed one year.

As of December 31, 2020, PGE had a $500 million revolving credit facility
scheduled to expire in November 2023. The facility allows for unlimited
extension requests, provided that lenders with a pro-rata share of more than 50%
of the facility approve the extension request. The revolving credit facility
supplements operating cash flows and provides a primary source of liquidity.
Pursuant to the terms of the agreement, the revolving credit facility may be
used as backup for commercial paper borrowings, to permit the issuance of
standby letters of credit, and for general corporate purposes. PGE may borrow
for one, two, three, or six months at a fixed interest rate established at the
time of the borrowing, or at a variable interest rate for any period up to the
then remaining term of the applicable credit facility.

The Company has a commercial paper program under which it may issue commercial
paper for terms of up to 270 days, limited to the unused amount of credit under
the revolving credit facility. The Company has elected to limit its borrowings
under the revolving credit facility to cover any potential need to repay
commercial paper that may be outstanding at the time. As of December 31, 2020,
PGE had no commercial paper outstanding.

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PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the consolidated balance sheets.

Under the revolving credit facility, as of December 31, 2020, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2020, the aggregate unused available credit capacity under the revolving credit facility was $500 million.



In addition, PGE has four letter of credit facilities under which the Company
has total capacity of $220 million. The issuance of such letters of credit is
subject to the approval of the issuing institution. Under these facilities,
letters of credit for a total of $60 million were outstanding as of December 31,
2020.

On April 9, 2020, PGE obtained a 364-day term loan from lenders in the aggregate
principal of $150 million. The term loan bears interest for the relevant
interest period at LIBOR plus 1.25%. The interest rate is subject to adjustment
pursuant to the terms of the loan. The credit agreement is classified as
Short-term debt on the Company's consolidated balance sheets and expires on
April 8, 2021, with any outstanding balance due and payable on such date.

Long-term Debt-During 2020, PGE issued a total of $430 million of FMBs.

On April 27, 2020, PGE issued $200 million of 3.15% Series FMBs due in 2030.

On December 10, 2020, the Company issued to certain institutional buyers in the private placement market $230 million aggregate principal amount of the Company's FMBs that consisted of:

•a series, due in 2027, in the amount of $160 million that will bear interest from its issuance date at an annual rate of 1.84%; and

•a series, due in 2032, in the amount of $70 million that will bear interest from its issuance date at an annual rate of 2.32%.



Pollution Control Revenue Bonds-On March 11, 2020, PGE completed the remarketing
of an aggregate principal amount of $119 million of Pollution Control Revenue
Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of
PCRBs that bear an interest rate of 2.125%, and $21 million aggregate principal
of PCRBs that bear an interest rate of 2.375%, both due in 2033. At the time of
remarketing, the Company chose a new interest rate period that was fixed term.
The new interest rate was based on market conditions at the time of remarketing.
The PCRBs are backed by the Company's Indenture of Mortgage by way of FMBs.
Interest is payable semi-annually on the PCRBs.

As of December 31, 2020, total long-term debt outstanding, net of $13 million of
unamortized debt expense, was $3,046 million, of which $160 million is scheduled
to mature in 2021.

Capital Structure-PGE's financial objectives include maintaining a common equity
ratio (common equity to total consolidated capitalization, including current
debt maturities and excluding lease obligations) of approximately 50% over time.
Achievement of this objective helps the Company maintain investment grade debt
ratings and provides access to long-term capital at favorable interest rates.
The Company's common equity ratio was 45.0% and 49.9% as of December 31, 2020
and 2019, respectively.


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Contractual Obligations and Commercial Commitments

The following table presents PGE's contractual obligations as of December 31, 2020 (in millions):


                                                                                                  There-
                                           2021       2022       2023       2024       2025        after        Total
Long-term debt                            $ 160      $   -      $   -      $  80      $   -      $ 2,819      $  3,059
Interest on long-term debt (1)              126        124        124        124        121        1,806         2,425
Capital and other purchase commitments      237         33         20          1          1           55           347
Purchased power and fuel:
Electricity purchases                       250        257        284        278        249        2,886         4,204
Capacity contracts                            9          9          9          9          9            -            45
Public Utility Districts                     21         19         18         17         17           39           131
Natural gas                                  57         42         37         43         43          578           800
Coal and transportation                      27         27         27         27         27            -           135
Pension Plan Contributions (2)                -          -         16         23         23            -            62

Finance and operating lease obligations 24 24 22 


  21         14          267           372
Total                                     $ 911      $ 535      $ 557      $ 623      $ 504      $ 8,450      $ 11,580




                                       `
(1) Future interest on long-term debt is calculated based on the assumption that
all debt remains outstanding until maturity. For debt instruments with variable
rates, interest is calculated for all future periods using the rates in effect
as of December 31, 2020.
(2) Contributions beyond 2025 are not estimated due to significant uncertainty
in financial market and demographic outcomes.

Other Financial Obligations

PGE has long-term power purchase agreements in place with certain public utility districts in the state of Washington.



The Company has acquired a percentage of the output of the Priest Rapids and
Wanapum Hydroelectric Projects under an agreement that requires PGE to pay its
proportionate share of the operating and debt service costs of the projects,
whether or not they are operable. The agreements further provide that, should
any other purchaser of output default on payments as a result of bankruptcy or
insolvency, PGE would be allocated a pro-rata share of both the output and the
operating and debt service costs of the defaulting purchaser.

Under an agreement for output of Douglas County PUD's Wells Hydroelectric
Project, PGE receives a share of the production in return for a fixed payment.
If any other purchaser of output were to default, PGE would receive a pro-rata
portion of the defaulting purchaser's share of the project output and associated
costs, with no limitation, regardless of the reason for the default. The share
of the project output is expected to decline over time as the public utility
district load grows and output is needed to serve that growth.

For additional information on these long-term power purchase agreements, see
"Public utility districts" in Note 16, Commitments and Guarantees, in the Notes
to Consolidated Financial Statements in Item 8.-"Financial Statements and
Supplementary Data."

Off-Balance Sheet Arrangements



Other than the items listed below, PGE has no off-balance sheet arrangements
that have, or are reasonably likely to have, a material current or future effect
on its consolidated financial condition, changes in financial condition,
revenues or expenses, results of operations, liquidity, capital expenditures, or
capital resources:
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•PGE has four letter of credit facilities that provide capacity up to a total of
$220 million. The issuance of such letters of credit is subject to the approval
of the issuing institution. Under these facilities, $60 million has been issued
as of December 31, 2020; and
•As a co-owner of Colstrip, PGE has provided surety bonds of $30 million as of
December 31, 2020 on behalf of the operator to ensure the operation and
maintenance of remedial and closure actions are carried out related to the
Administrative Order on Consent Regarding Impacts Related to Wastewater
Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Station,
Colstrip Montana (the AOC) as required by the Montana Department of
Environmental Quality. It is possible that each co-owner of Colstrip will be
required, at some future point, to post additional financial assurance to
support further performance by the operator of closure and remediation actions
under the AOC.

Critical Accounting Policies and Estimates



The preparation of consolidated financial statements in conformity with GAAP
requires that management apply accounting policies and make estimates and
assumptions that affect amounts reported in the statements. The following
accounting policies represent those that management believes are particularly
important to the consolidated financial statements and that require the use of
estimates, assumptions, and judgments to determine matters that are inherently
uncertain.

Regulatory Accounting

As a rate-regulated enterprise, PGE applies regulatory accounting, which
includes the recognition of regulatory assets and liabilities on the Company's
consolidated balance sheets. Regulatory assets represent probable future revenue
associated with certain incurred costs that are expected to be recovered from
customers through the ratemaking process. Regulatory liabilities represent
probable future reductions in revenues associated with amounts that are expected
to be credited or refunded to customers through the ratemaking process.
Regulatory accounting is appropriate as long as prices are established or
subject to approval by independent third-party regulators, prices are designed
to recover the specific enterprise's cost of service, and, in view of demand for
service, it is reasonable to assume that prices set at levels that will recover
costs can be charged to and collected from customers. Amortization of regulatory
assets and liabilities is reflected in the statement of income over the period
in which they are included in customer prices.

If future recovery of regulatory assets is not probable, PGE would expense such
items in the period such determination is made. Further, if PGE determines that
all or a portion of its utility operations no longer meet the criteria for
continued application of regulatory accounting, the Company would be required to
write off those regulatory assets and liabilities related to operations that no
longer meet requirements for regulatory accounting. Discontinued application of
regulatory accounting would have a material impact on the Company's results of
operations and financial position.

Asset Retirement Obligations



PGE recognizes AROs for legal obligations related to dismantlement and
restoration costs associated with the future retirement of tangible long-lived
assets. Upon initial recognition of AROs that are measurable, the
probability-weighted future cash flows for the associated retirement costs,
discounted using a credit-adjusted risk-free rate, are recognized as both a
liability and as an increase in the capitalized carrying amount of the related
long-lived assets. Due to the long lead time involved, a market-risk premium
cannot be determined for inclusion in future cash flows. In estimating the
liability, management must utilize significant judgment and assumptions in
determining whether a legal obligation exists to remove assets. Other estimates
may be related to lease provisions, ownership agreements, licensing issues, cost
estimates, inflation, and certain legal requirements. Estimates for ARO
liabilities are generally based on site-specific studies and are periodically
subject to updates and changes that may arise over time.

Capitalized asset retirement costs related to electric utility plant are depreciated over the estimated life of the related asset and included in Depreciation and amortization expense in the consolidated statements of income. For revisions


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to ARO liabilities in which the related asset is no longer in service, the
corresponding offset is recorded as a Regulatory asset on the consolidated
balance sheets, except for those AROs related to non-utility assets which is
charged to Depreciation and amortization on the consolidated statements of
income. Accretion of the ARO liability is classified as Depreciation and
amortization expense in the consolidated statements of income. Accumulated asset
retirement removal costs that do not qualify as AROs have been reclassified from
accumulated depreciation to regulatory liabilities in the consolidated balance
sheets.

Contingencies

PGE has various unresolved legal and regulatory matters about which there is
inherent uncertainty, with the ultimate outcome contingent upon several factors.
Such contingencies are evaluated using the best information available. A loss
contingency is accrued, and disclosed if material, when it is probable that an
asset has been impaired, or a liability incurred, and the amount of the loss can
be reasonably estimated. If a range of probable loss is established, the minimum
amount in the range is accrued, unless some other amount within the range
appears to be a better estimate. If the probable loss cannot be reasonably
estimated, no accrual is recorded, but the loss contingency and the reasons to
the effect that it cannot be reasonably estimated are disclosed. Material loss
contingencies are disclosed when it is reasonably possible that an asset has
been impaired, or a liability incurred. Established accruals reflect
management's assessment of inherent risks, credit worthiness, and complexities
involved in the process. There can be no assurance as to the ultimate outcome of
any particular contingency.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.



PGE is exposed to various forms of market risk, consisting primarily of
fluctuations in commodity prices, foreign currency exchange rates, and interest
rates, as well as credit risk. Any variations in the Company's market risk or
credit risk may affect its future financial position, results of operations, or
cash flows, as discussed below.

Energy Risk Management



During 2020, PGE had a Risk Management Committee (RMC), whose responsibilities
included providing oversight of the adequacy and effectiveness of corporate
policies, guidelines, and procedures for market and credit risk management
related to the Company's energy portfolio management activities. The RMC
consisted of officers and Company representatives with responsibility for risk
management, finance and accounting, information technology, utility operations,
legal, and rates and regulatory affairs. The RMC reviewed and approved adoption
of policies and procedures, and monitored compliance with policies, procedures,
and limits on a regular basis through reports and meetings. The RMC also
reviewed and recommended risk limits that were subject to approval by PGE's
Board of Directors.

In response to the energy trading losses realized in the third quarter of 2020
(for more information see "Energy Trading" in the Overview section in Item
7.-"Management's Discussion and Analysis of Financial Condition and Results of
Operations.") the Company began taking actions to enhance oversight of energy
trading and associated risk management reporting, policies, and practices. As a
result, effective February 1, 2021, the RMC has been subsumed by the Executive
Risk Committee (ERC) whose primary purpose is to oversee, guide, and support the
prudent management of the Company's risks. In addition to assuming the
responsibilities previously held by the RMC, the ERC's responsibilities have
been enhanced to include improved risk reporting to ensure greater visibility
into portfolio risk and manage alignment with the Company's Board-approved risk
strategy and tolerances.

Commodity Price Risk

PGE is exposed to commodity price risk as its primary business is to provide
electricity to its retail customers. The Company engages in price risk
management activities to manage exposure to volatility in net power costs for
its retail customers. The Company uses power purchase and sale contracts to
supplement its own generation and to respond to fluctuations in the demand for
electricity and variability in generating plant operations. The Company also
enters into contracts for the purchase and sale of fuel for the Company's
natural gas- and coal-fired generating
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plants. These contracts for the purchase of power and fuel expose the Company to
market risk. The Company uses instruments such as: i) forward contracts, which
may involve physical delivery of an energy commodity; ii) financial swap and
futures agreements, which may require payments to, or receipt of payments from,
counterparties based on the differential between a fixed and variable price for
the commodity; and iii) option contracts to mitigate risk that arises from
market fluctuations of commodity prices. The Company does not intend to engage
in trading activities for non-retail purposes.

A portion of PGE's energy portfolio subject to commodity price risk experienced
significant losses during the third quarter of 2020. In August 2020, wholesale
electricity prices increased substantially at various market hubs due to extreme
weather conditions, constraints to regional transmission facilities, and changes
in power supply in the West. As a result of the convergence of these conditions,
the Company's energy portfolio experienced realized losses of $127 million in
the third quarter of 2020. PGE no longer has net market exposure related to
these positions and will not pursue regulatory recovery of the related losses.
For additional information see "Energy Trading" in the Overview section in Item
7.-"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

Assuming no changes in market prices and interest rates, the following table
presents the years in which the net unrealized (gains)/losses recorded as of
December 31, 2020 related to PGE's derivative activities would become realized
as a result of the settlement of the underlying derivative instrument (in
millions):
                                         2021       2022      2023

2024 2025 Thereafter Total


       Commodity contracts:
       Electricity                      $   9      $  4      $  8      $  8      $  9      $      100      $ 138
       Natural gas                        (27)       (5)        -         -         -               -        (32)
           Net unrealized (gain)/loss   $ (18)     $ (1)     $  8      $  8      $  9      $      100      $ 106



PGE reports energy commodity derivative fair values as a net asset or liability,
which combines purchases and sales expected to settle in the years noted above.
Energy commodity fair values exposed to commodity price risk are primarily
related to purchase contracts, which are slightly offset by sales.

PGE's energy portfolio activities are subject to regulation, with related costs
included in retail prices approved by the OPUC. The timing differences between
the recognition of gains and losses on certain derivative instruments and their
realization and subsequent recovery in prices are deferred as regulatory assets
and regulatory liabilities to reflect the effects of regulation, significantly
mitigating commodity price risk for the Company. As contracts are settled, these
deferrals reverse and are recognized as Purchased power and fuel in the
statements of income and expected to be included in the PCAM. PGE remains
subject to cash flow risk in the form of collateral requirements based on the
value of open positions and regulatory risk if recovery is disallowed by the
OPUC. PGE attempts to mitigate both types of risks through prudent energy
procurement practices.

Foreign Currency Exchange Rate Risk



PGE is exposed to foreign currency risk associated with natural gas forward and
swap contracts denominated in Canadian dollars. Foreign currency risk is the
risk of changes in value of pending financial obligations in foreign currencies
that could occur prior to the settlement of the obligation due to a change in
the value of that foreign currency in relation to the U.S. dollar. PGE mitigates
its exposure to fluctuations in the Canadian exchange rate with an appropriate
hedging strategy.

As of December 31, 2020, a 10% change in the value of the Canadian dollar would
result in an immaterial change in exposure for transactions that will settle
over the next twelve months.


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Interest Rate Risk



To meet short-term cash requirements, PGE has the ability to issue commercial
paper for terms of up to 270 days and has a revolving credit facility that
permits same day borrowings. Although any borrowings under the commercial paper
program or the revolving credit facility carry a fixed rate during their
respective terms, the short-term nature of such borrowings subjects the Company
to fluctuations in interest rates that result from changes in market conditions.
As of December 31, 2020, PGE had no borrowings outstanding under its revolving
credit facility and no commercial paper outstanding.

PGE currently has no financial instruments to mitigate risk related to changes
in short-term interest rates, including those on commercial paper; however, it
may consider such instruments in the future as considered necessary.

As of December 31, 2020, the total fair value and carrying amounts, excluding
unamortized debt expense, by maturity date of PGE's long-term debt are as
follows (in millions):

                                    Total                        Carrying Amounts by Maturity Date
                                    Fair                                                                    There-
                                    Value           Total          2021       2022      2023      2024       after
First Mortgage Bonds              $ 3,683      $   2,940          $ 160      $  -      $  -      $ 80      $ 2,700

Pollution Control Revenue Bonds       125            119              -         -         -         -          119
Total                             $ 3,808      $   3,059          $ 160      $  -      $  -      $ 80      $ 2,819

As of December 31, 2020, PGE had no long-term debt instruments subject to interest rate risk exposures.

Credit Risk



PGE is exposed to credit risk in its commodity price risk management activities
related to potential nonperformance by counterparties. The Company manages the
risk of counterparty default according to its credit policies by performing
financial credit reviews, setting limits and monitoring exposures, and requiring
collateral (in the form of cash, letters of credit, and guarantees) when needed.
PGE also uses standardized enabling agreements and, in certain cases, master
netting agreements, which allow for the netting of positive and negative
exposures under multiple agreements with counterparties. Despite such mitigation
efforts, defaults by counterparties may periodically occur. Based upon periodic
review and evaluation, allowances are recorded as needed to reflect credit risk
related to wholesale accounts receivable.

The large number and diversified base of residential, commercial, and industrial
customers, combined with the Company's ability to discontinue service,
contribute to reduce credit risk with respect to trade accounts receivable from
retail sales. Estimated provisions for uncollectible accounts receivable related
to retail sales are provided for such risk.

As of December 31, 2020, PGE's credit risk exposure is $48 million for commodity
activities, of which $46 million is with externally-rated investment grade
counterparties. The underlying transactions that make up the exposure will
mature from 2021 to 2024. The exposure is included in accounts receivable and
price risk management assets, offset by related accounts payable and price risk
management liabilities.

Investment grade counterparties include those with a minimum credit rating on
senior unsecured debt of Baa3 (as assigned by Moody's) or BBB- (as assigned by
S&P), and also those counterparties whose obligations are guaranteed or secured
by an investment grade entity. The credit exposure includes activity for
electricity and natural gas forward, swap, and option contracts. Posted
collateral may be in the form of cash or letters of credit, and may represent
prepayment or credit exposure assurance.

Omitted from the market risk exposures discussed above are long-term power purchase contracts with certain public utility districts in the state of Washington. These contracts currently provide PGE with a percentage share of hydro


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facility output in exchange for an equivalent percentage share of operating and
debt service costs. These contracts expire at varying dates through 2052. For
additional information, see "Public utility districts" in Note 16, Commitments
and Guarantees, in the Notes to Consolidated Financial Statements in
Item 8.-"Financial Statements and Supplementary Data." Management believes that
circumstances that could result in the nonperformance by these counterparties
are remote.

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