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Edgar Glimpses

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, future loads, the outcome of litigation and regulatory proceedings, future 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. 27


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


• 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;

• complications arising from PGE's jointly-owned generating facilities,

including changes in ownership, adverse regulatory outcomes or operational

failures that result in legal or environmental liabilities or unanticipated costs related to replacement power or repair costs

• the 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, which could require

PGE to issue additional letters of credit or post additional cash as

collateral with counterparties pursuant to power and natural gas purchase


• 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; 28


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• 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, and industrial customer growth, and in

demographic patterns, in PGE's service territory;

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

• cyber security attacks, data security breaches, or other malicious acts

that cause damage to the Company's generation and transmission facilities

or 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 earthquake, flood, drought,

lightning, wind, and fire;

• changes in financial or regulatory accounting principles or policies

imposed by governing bodies; and

• acts of war or terrorism.

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


Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company's consolidated financial statements contained in this report, and other periodic and current reports filed with the SEC. PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale purchase and sale of electricity and natural gas in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory. In addition, the Company participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE is 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 greenhouse gas emissions, keep the power grid reliable and secure, and ensure prices are affordable, especially for the most vulnerable customers. The Company's strategy strives to balance these interests. PGE plans to: • Decarbonize the power supply with a goal of more than 80% carbon reduction from 1990 levels by the year 2050; • Electrify sectors of the economy like transportation and buildings that are also transforming to reduce greenhouse gas emissions; and 29


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• 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 greenhouse gas reduction goals. PGE's framework for achieving a clean energy future is informed and enabled by: i) customer choice programs; ii) carbon legislation; iii) the resource planning process; and iv) the renewable cost recovery framework. Customer Choice Programs-PGE's customers continue to express a commitment to purchasing clean energy, as over 225,000 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 megawatts (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. Carbon Legislation-SB 1547 set a benchmark for how much electricity must come from renewable sources like wind and solar (50 percent by 2040) 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 future effects under 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 RECs generated from facilities that become

operational after 2022 to five years, but continued unlimited lifespan for

all existing RECs and allowance for the generation of additional unlimited

RECs for a period of five years for projects online before December 31, 2022; and

• An allowance for energy storage costs related to renewable energy in the

Company's Renewable Adjustment Clause (RAC) filings.

In response to SB 1547, the Company filed a tariff request in 2016 to accelerate recovery of PGE's investment in the Colstrip facility from 2042 to 2030. During 2019, the owners of Colstrip Units 1 and 2 announced that they would permanently close those two units and have retired them as of January 2020. Although PGE has no direct ownership interest in those two units, the Company does have a 20% ownership share in Colstrip Units 3 and 4, which utilize certain common facilities with Units 1 and 2. Although PGE is currently scheduled to recover the costs of Colstrip by 2030, some co-owners of Units 3 and 4 have taken actions to recover their costs by 2025 and 2027. The Company continues to evaluate its ongoing investment in Colstrip. 30


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

The Company continues with plans to cease coal-fired operation at its Boardman generating plant at the end of 2020.

During the 2019 State legislative session, House Bill (HB) 2020 was introduced, which would have authorized a comprehensive cap and trade package in the State and would have granted the OPUC direct authority to address climate change. Although HB 2020 was not enacted in 2019, an amended version has been reintroduced in the 35-day legislative session, which began on February 3, 2020. The new proposal, Senate Bill (SB) 1530, is also a cap and trade package that includes 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 is limited to that of an economic regulator. The Company will continue to monitor this legislative effort. 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 average MW (MWa) of qualifying renewable resources. The prevailing bid, Wheatridge Renewable Energy Facility (Wheatridge), will be an energy facility in eastern Oregon that combines 300 MW of wind generation and 50 MW of solar generation with 30 MW of battery storage. PGE will own 100 MW of the wind resource with an investment of approximately $160 million. Subsidiaries of NextEra Energy Resources, LLC will own the balance of the 300 MW wind resource, along with the solar and battery components, and sell their portion of the output to PGE under 30-year power purchase agreements. PGE has the option to purchase the underlying assets of the power purchase agreements on the 12th anniversary of the commercial operation date of the wind facility. As of December 31, 2019, the Company has recorded $17 million, including the allowance for funds used during construction (AFDC), in construction work-in-progress (CWIP) related to Wheatridge. The wind component of the facility is expected to be operational by December 2020 and qualify for PTCs at the 100 percent level. Construction of the solar and battery components is planned for 2021 and is also expected to qualify for federal investment tax credits. In July 2019, PGE submitted its 2019 Integrated Resource Plan (2019 IRP) to the OPUC. The initial plan and modifications proposed by PGE within the docket (LC 73) would set forth the following actions the Company would undertake over the next four years to acquire the resources identified: • Customer actions-

• cost-effective energy efficiency

• reliance on demand response, and

• dispatchable customer storage and standby generation.

• Renewable actions-a Renewable RFP seeking up to 150 MWa to come online by

the end of 2024 and contribute to meeting capacity needs; and 31


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• Capacity actions-a concurrent procurement process that will allow PGE to

pursue cost-competitive agreements for existing capacity in the region and

to conduct a non-emitting Capacity RFP seeking new dispatchable resources.

Through the renewable and capacity actions, PGE seeks up to approximately 150 MWa of additional non-emitting energy resources and up to approximately 700 MW of capacity contribution from a combination of renewables, existing resources, and new non-emitting dispatchable capacity resources, such as energy storage.

The regulatory schedule for the 2019 IRP would lead to an OPUC order in the first quarter of 2020.

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 General Rate Case (2019 GRC) Order, the OPUC authorized the inclusion of prudent costs of energy storage projects associated with renewables in future RAC filings to be made to the OPUC, under certain conditions. Although no significant filings have been submitted under the RAC during 2018, the Company did submit a RAC filing for Wheatridge in the fourth quarter of 2019. Electrify other sectors of the economy-PGE is working toward an equitable, safe, and clean energy future. Recent and future enhancements to the grid to enable a seamless platform include: • The use of electricity in more applications such as electric vehicles and

heat pumps;

• The integration of new, geographically-diverse energy markets;

• The deployment of new technologies like energy storage, communications

networks, automation and control systems for flexible loads, and distributed generation; • The development of connected neighborhood microgrids and smart communities; and

• The use of data and analytics to better predict demand and support energy

saving customer programs.

In July 2019, PGE's Board approved plans to construct an Integrated Operations Center (IOC) as a key step to supporting this strategy, at an estimated total cost of $200 million, excluding AFDC. The IOC will centralize mission-critical operations, including those that are planned as part of the integrated grid strategy. This secure, resilient facility will include infrastructure to support and enhance grid operations and co-locate primary support functions. As of December 31, 2019, the Company has recorded $30 million, including AFDC, in CWIP 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 Legislature enacted Senate Bill 1044, which establishes Oregon's zero emissions vehicle goals in statute at 250,000 vehicle sales by 2025 and 95% 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: 32


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General Rate Case-In 2018, PGE filed with the OPUC a general rate case based on a 2019 test year. The filing sought recovery of costs related to better serving customers and building a smarter, more resilient system and included the expectation of higher net variable power costs in 2019. In December 2018, the OPUC issued an order that, when combined with customer credits and the effects of tax reform, would result in an overall annual increase in PGE's revenues of $9 million, effective January 1, 2019. In addition, the OPUC approved a capital structure of 50% debt and 50% equity, a return on equity of 9.50%, a cost of capital of 7.30%, and rate base of $4.75 billion.

The general rate case filings, as well as copies of the orders, direct testimony, exhibits, and stipulations are available on the OPUC website at

Power Costs-Pursuant to the AUT process, PGE annually files an estimate of power costs for the following year. As approved by the OPUC in December 2018, the 2019 GRC included a final projected increase in power costs for 2019, and a corresponding increase in annual revenue requirement, of $25 million from 2018 levels, which was reflected in customer prices effective January 1, 2019. The filing for the 2020 AUT indicated that power costs are expected to rise in 2020 by $27 million. Under the PCAM for 2019, NVPC was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for 2019 during the second half of 2020 with a decision expected in the fourth quarter 2020. 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, 2019, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. In a Record of Decision issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total cost of $1.7 billion, However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor, although such costs could be material to PGE's financial position. The impact of such costs to the Company's results of operations is mitigated by the PHERA mechanism. As approved by the OPUC, the Company's 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. 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 believes the City's preliminary findings are not consistent with previous audit conclusions, which found that the Company appropriately calculated gross revenues in determining franchise fees. PGE believes it has good standing for maintaining the historical approach to determining License Fees and has not recorded a liability for the City's assertion. The City has not provided its Final Letter of Determination, which is an initial step in an ongoing resolution process. 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 33


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2019 GRC, the Company's capital cost of the asset is 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 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 (Order) concluding that the OPUC lacks authority under Oregon law to allow deferrals of any costs related to capital investments. In the Order, the OPUC acknowledged that this decision is contrary to its past limited practice of allowing deferrals related to capital investments and will 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. In response to the 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 OPUC Order with the Oregon Court of Appeals. While procedural steps pursuant to this petition continue, PGE believes that the costs incurred to date associated with the customer information system were prudently incurred and has not withdrawn its deferral application to recover the revenue requirement of this capital project. During 2018, PGE deferred a total of $12 million of expenses related to the customer information system. However, the Order has impacted the probability of recovery of deferred expenses and, as such, the Company has 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. Any amounts that may ultimately be approved by the OPUC in subsequent proceedings would be recognized in earnings in the period of such approval; however, there is no assurance that such recovery would be granted by 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 collection of $14 million attributed to the year ended December 31, 2019, which resulted from variances between actual weather-adjusted use per customer and that projected in the 2019 GRC. Collections under the decoupling mechanism are subject to an annual limitation of 2% of the applicable tariff schedule. For 2019, this limitation would have been, in total, $27 million for residential and commercial customers now subject to the decoupling mechanism. Any collection from customers for the 2019 year is expected to occur over a one-year period, which would begin January 1, 2021. The Company recorded a deferral for an estimated collection of $2 million during the year ended December 31, 2018, as a result of variances from amounts established in the 2018 GRC. Collection for the 2018 year is expected to occur over a one-year period, which began January 1, 2020. Storm Restoration Costs-Beginning in 2011, the OPUC authorized the Company to collect $2 million annually from retail customers to cover incremental expenses related to major storm damages, and to defer any amount not utilized in the current year. Under the 2019 GRC, the annual collection amount increased to $4 million beginning in 2019. Due to a series of storm events in the first half of 2017, the Company exhausted the storm collection authorized for 2017. Consequently, PGE was exposed to the incremental costs related to such major storm events, which totaled $9 million, net of the amount collected in 2017. 34


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As a result of the additional costs incurred, PGE filed an application with the OPUC requesting authorization to defer incremental storm related restoration costs from the date of the application, in the first quarter of 2017, through the end of 2017. In the third quarter of 2019, the OPUC issued an order that denied the Company's application for deferral. Although PGE had deferred the incremental expense in 2017, an offsetting reserve was also recorded at that time, thus the OPUC decision had no impact to the Company's current results of operations. Corporate Activity Tax-In 2019, the State enacted HB 3427, which imposes a new gross receipts tax on companies with annual revenues in excess of $1 million and will apply to tax years beginning on or after January 1, 2020. The legislation defines that the tax will apply to commercial activities sourced in Oregon, less a deduction for 35% of the greater of "cost inputs" or "labor costs." The resulting amount will be taxed at 0.57%. In anticipation of the incremental annual expense as a result of this new tax, PGE submitted a tariff filing with the OPUC in the fourth quarter 2019 to establish a balancing account and provide for an estimated recovery of $7 million in customer prices in 2020. The Company expects to revisit the expected tax consequences annually and revise the annual tariff accordingly. On January 29, 2020. the OPUC issued an order approving the tariff and the associated deferral, balancing account, and automatic adjustment clause, with the provision that it be included in base rates at a future date to be agreed upon by the parties.

The discussion that follows in this MD&A provides additional information related to the Company's operating activities, legal, regulatory, and environmental matters, results of operations, and liquidity and financing activities.

Operating Activities-As an electric utility, PGE closely follows and plans for customer demand in its service territory as it strives to meet the needs and expectations of its retail customers through the generation of power from its own facilities or purchase of power in the wholesale market. Customers and Demand-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. See the Seasonality section of "Customers and Revenues" within Item 1. Business for further information regarding seasonal fluctuations. In 2019, retail energy deliveries increased 1.2% from 2018 as industrial deliveries continued to grow. Residential customer deliveries, which are most sensitive to fluctuations in weather, also increased slightly, as 2019 saw cooler temperatures during the heating season partially offset by fewer cooling degree-days during the summer cooling season, while commercial customer deliveries decreased. For 2019 and 2018, the average number of retail customers and deliveries, by customer type, were as follows: 2019 2018 Increase/ Average Average (Decrease) Number of Energy Number of Energy in Energy Customers Deliveries * Customers Deliveries * Deliveries Residential 779,673 7,471 772,389 7,416 0.7 % Commercial (PGE sales only) 109,521 6,653 108,570 6,783 (1.9 )% Direct Access 563 665 537 647 2.8 % Total Commercial 110,084 7,318 109,107 7,430 (1.5 )% Industrial (PGE sales only) 193 3,181 203 2,987 6.5 % Direct Access 69 1,490 67 1,389 7.3 % Total Industrial 262 4,671 270 4,376 6.7 % Total (PGE sales only) 889,387 17,305 881,162 17,186 0.7 % Total Direct Access 632 2,155 604 2,036 5.8 % Total 890,019 19,460 881,766 19,222 1.2 % * In thousands of MWh. 35


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In 2019, heating degree-days, an indication of electricity use for heating, were 1% above the 15-year average and 13% higher than 2018. Cooling degree-days, a similar indication of the extent to which customers are likely to have used electricity for cooling, although 6% above the 15-year moving average, were 18% below the 2018 levels. Residential energy deliveries were 0.7% higher in 2019 than 2018, driven by a 0.9% increase in the average number of customers. Weather impacted residential deliveries as it served to increase comparable deliveries during the heating season and reduce comparable deliveries during the summer season. See "Revenues" in the 2019 Compared to 2018 section of Results of Operations within this Item 7, for further information on heating and cooling degree days.

Commercial energy deliveries declined in several sectors including food and merchandise stores and government and education. Irrigation deliveries were also lower in 2019, which saw a relatively mild summer, than 2018, which had an unusually hot and dry summer irrigation season.

The 6.7% increase in industrial energy deliveries is due to continued strength in the high-tech manufacturing sector as well as the reopening in 2019 of a large paper facility that had closed in late 2017.

On a weather-adjusted basis, total retail deliveries increased 0.1% from 2018. The increase was driven by 6.8% growth in industrial energy deliveries which were largely offset by decreases in residential and commercial energy deliveries of 1.9% and 1.6% respectively. Average usage per customer for smaller energy users continues to decline, driven by ongoing market and program-based energy efficiency gains. PGE projects that retail energy deliveries for 2020 will be approximately 0.5% - 1.5% above 2019 weather-adjusted levels, reflecting strength in industrial deliveries, partially offset by continued energy efficiency and conservation efforts. ESSs supplied Direct Access customers with energy representing 11% of the Company's total retail energy deliveries during 2019 and 2018. The maximum retail load allowed to be supplied under the fixed three-year and minimum five-year opt-out programs represent 14% of the Company's total retail energy deliveries for 2019, and 2018. With the adoption of the New Large Load Direct Access program, the percentage of the Company's energy deliveries supplied by ESSs is expected to increase by as much as 6%. 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. 36


Table of Contents Actual energy provided Actual energy provided compared to projected as a percentage of Plant availability (1) levels (2) total retail load 2019 2018 2019 2018 2019 2018 Generation: Thermal: Natural gas 92 % 92 % 86 % 89 % 45 % 41 % Coal (3) 87 94 104 69 24 17 Wind 96 92 90 95 9 10 Hydro 93 93 81 96 8 8

(1) Plant availability represents the percentage of the year the plant was

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 85% in 2019, compared with 82% in 2018.

Energy received from PGE-owned and jointly-owned thermal plants increased 20% in 2019 compared to 2018, primarily as a result of increased economic dispatch at Boardman. 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. Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 20% in 2019 compared to 2018, due to less favorable hydro conditions in 2019. 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" section of Results of Operations in this Item 7, for further detail on regional hydro results. Energy received from PGE-owned wind resources and under contracts decreased 8% in 2019 compared to 2018, due to less favorable wind conditions in 2019. Energy expected to be received from wind generating resources (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 shortfalls, PTCs have not materialized to the extent contemplated in the Company's prices. Under the PCAM, PGE may share with customers a portion of cost variances associated with NVPC. Subject to a regulated earnings test, 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. The following is a summary of the results of the Company's PCAM as calculated for regulatory purposes for 2019, and 2018:

• For 2019, actual NVPC was above baseline NVPC by $5 million, which was

within the established deadband range. Accordingly, no estimated

collection from customers was recorded as of December 31, 2019. A final

determination regarding the 2019 PCAM results will be made by the OPUC

through a public filing and review in 2020.

• For 2018, actual NVPC was below baseline NVPC by $3 million, which was

within the established deadband range. Accordingly, no estimated refund to

customers was recorded as of December 31, 2018. A final determination

regarding the 2018 PCAM results was made by the OPUC through a public

filing and review in 2019, which confirmed no refund to customers pursuant to the PCAM for 2018. 37


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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 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, 2019 2018 2017 As % As % As % Amount of Rev Amount of Rev Amount of Rev Total revenues (1) $ 2,123 100 % $ 1,991 100 % $ 2,009 100 % Purchased power and fuel (1) 614 29 571 30 592 30 Gross margin 1,509 71 1,420 70 1,417 70 Other operating expenses: Generation, transmission and distribution 323 15 292 15 309 16 Administrative and other 290 14 271 13 260 13 Depreciation and amortization 409 19 382 19 345 17 Taxes other than income taxes 134 6 129 6 123 6 Total other operating expenses 1,156 54 1,074 53 1,037 52 Income from operations 353 17 346 17 380 18 Interest expense, net (2) 128 6 124 6 120 6 Other income: Allowance for equity funds used during construction 10 - 11 1 12 1 Miscellaneous income (expense), net 6 - (4 ) - 1 - Other income, net 16 - 7 1 13 1 Income before income taxes 241 11 229 12 273 13 Income tax expense 27 1 17 1 86 4 Net income $ 214 10 % $ 212 11 % $ 187 9 %

(1) As reported on PGE's Consolidated Statements of Income. (2) Includes an allowance for borrowed funds used during construction of $5 million in 2019 and $6 million in 2018 and 2017.



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Revenues, energy deliveries (presented in MWh), and average number of retail customers consist of the following for the years presented:

Years Ended December 31, 2019 2018 2017 Revenues(1) (dollars in millions): Retail: Residential $ 981 46 % $ 948 48 % $ 969 48 % Commercial 636 30 647 32 652 32 Industrial 196 9 185 9 192 10 Direct Access 44 2 43 2 37 2 Subtotal 1,857 87 1,823 91 1,850 92 Alternative revenue programs, net of amortization 2 - 3 - - - Other accrued (deferred) revenues, net(2) 22 2 (45 ) (2 ) 10 1 Total retail revenues 1,881 89 1,781 89 1,860 93 Wholesale revenues 170 8 159 8 105 5 Other operating revenues 72 3 51 3 44 2 Total revenues $ 2,123 100 % $ 1,991

100 % $ 2,009 100 %

Energy deliveries (MWh in thousands): Retail: Residential 7,471 31 % 7,416 31 % 7,880 34 % Commercial 6,653 28 6,783 29 6,932 30 Industrial 3,181 13 2,987 13 2,943 13 Subtotal 17,305 72 17,186 73 17,755 77 Direct access: Commercial 665 3 647 3 623 3 Industrial 1,490 6 1,389 6 1,340 6 Subtotal 2,155 9 2,036 9 1,963 9 Total retail energy deliveries 19,460 81 19,222 82 19,718 86 Wholesale energy deliveries 4,669 19 4,290 18 3,193 14 Total energy deliveries 24,129 100 % 23,512

100 % 22,911 100 %

Average number of retail customers: Residential 779,673 88 % 772,389 88 % 762,211 88 % Commercial 109,521 12 108,570 12 107,364 12 Industrial 193 - 203 - 199 - Direct access 632 - 604 - 559 - Total 890,019 100 % 881,766 100 % 870,333 100 %

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

the Company and revenues from the delivery of energy to those customers that

purchase their energy from ESSs. Commercial revenues from ESS customers were

$18 million for 2019 and 2018, and $17 million for 2017. Industrial revenues

from ESS customers were $26 million, $25 million, and $20 million for 2019,

2018, and 2017, respectively. (2) Amounts for the years ended December 31, 2019 and 2018 are primarily comprised

of $23 million of amortization and $45 million of deferral, respectively,

related to the 2018 net tax benefits due to the change in corporate tax rate

under the United States Tax Cuts and Jobs Act of 2017 (TCJA). 39


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

Years Ended December


2019 2018


Sources of energy (MWh in thousands): Generation: Thermal: Natural gas 8,342 36 % 7,515 33 % 6,228 28 % Coal 4,416 19 % 3,106 14 3,344 15 Total thermal 12,758 55 10,621 47 9,572 43 Hydro 1,407 6 1,474 7 1,774 8 Wind 1,706 8 1,875 8 1,641 8 Total generation 15,871 69 13,970 62 12,987 59 Purchased power: Term 5,882 25 6,714 30 7,192 33 Hydro 1,048 5 1,603 7 1,648 7 Wind 284 1 286 1 264 1 Total purchased power 7,214 31 8,603 38 9,104 41 Total system load 23,085 100 % 22,573 100 % 22,091 100 % Less: wholesale sales (4,669 ) (4,290 ) (3,193 ) Retail load requirement 18,416 18,283 18,898 Net income for the year ended December 31, 2019 was $214 million, or $2.39 per diluted share, compared with $212 million, or $2.37 per diluted share, for the year ended December 31, 2018. Among the factors that led to the $2 million, or 1%, increase in net income was Gross margin, which increased $89 million primarily due to a $132 million increase in revenues, driven by higher retail prices as a result of the 2019 GRC and other supplemental tariffs. Partially offsetting the revenue increase was a $43 million increase in Purchased power and fuel expense, as a result of a $46 million increase in the cost of purchased power. Although purchased power volumes were lower due to economic dispatch decisions, the resulting savings were diminished by the increased expenses associated with higher utilization of Company-owned generation. Largely offsetting the increase in Gross margin were Operating expense increases of $82 million, which included $27 million higher depreciation and amortization expense resulting from capital additions, a $13 million increase in distribution expenses due to higher vegetation management and wildfire mitigation efforts, $13 million higher labor and benefit expenses, a $10 million gain from the cash settlement of Carty litigation in 2018 that did not recur, and a $10 million increase in income tax expense.

2019 Compared to 2018

Total revenues increased $132 million, or 6.6%, in 2019 compared with 2018 as a result of the items discussed below.

Total retail revenues increased $100 million, or 5.6%, in 2019 compared with 2018, primarily due to the net effect of: • $66 million as a result of customer price changes in the 2019 GRC, the AUT, and the amortization in prices of the decoupling mechanism;

• $23 million that resulted from the 1.2% overall increase in retail energy

deliveries consisting of a 0.7% increase in residential deliveries, and a

6.7% increase in industrial deliveries, partially offset by a 1.5%

decrease in commercial deliveries. The effects of weather on electricity

demand is reflected predominantly in the Residential revenue line in the table above. The table below shows that 2019 had more heating degree days

than 2018 during the heating season, although the effect was partially

offset by the relative lack of cooling degree-days during the summer

months in 2019. For further information on customer demand, see "Customers

and Demand" in the Overview section of this Item 7; and

• $12 million resulting from the combination of various supplemental tariffs

and adjustments, the largest of which pertain to the demand response pilot

program and a major maintenance expense deferral, which was offset in Generation, transmission and distribution expense. Total heating degree-days in 2019 were slightly above the 15-year average and up considerably from total heating degree-days in 2018. Total cooling degree-days in 2019 exceeded the 15-year average by 6% although were 18% below the 2018 total. The following table presents the number of heating and cooling degree-days in 2019 and 2018, along with the 15-year averages, reflecting that weather had a considerable influence on comparative energy deliveries: Heating Degree-Days

Cooling Degree-Days

15-Year 15-Year 2019 2018 Average 2019 2018 Average 1st quarter 1,992 1,766 1,830 - - - 2nd quarter 467 471 653 102 116 88 3rd quarter 83 69 75 462 575 440 4th quarter 1,623 1,396 1,582 - 1 3 Total 4,165 3,702 4,140 564 692 531

Increase (decrease) from the 15-year average 1 % (11 )% 6 % 30 % Wholesale revenues result from sales of electricity to utilities and power marketers made in the Company's efforts to secure reasonably priced power for its retail customers, manage risk, and administer its current long-term wholesale contracts. Such sales can vary significantly from year to year as a result of economic conditions, power and fuel prices, hydro and wind availability, and customer demand. In 2019, an $11 million, or 7%, increase in wholesale revenues over 2018 resulted from $14 million related to a 9% increase in wholesale sales volume partially offset by $3 million from a 1% decrease in average prices received when the Company sold power into the wholesale market. Other operating revenues increased $21 million, or 41%, in 2019 from 2018, primarily as a result of an $8 million increase attributable to the sale of excess natural gas not used to fuel the Company's generating facilities. Other contributors to the increase included $4 million related to a customer project that is offset with corresponding expense increases in Generation, transmission and distribution expense and $3 million as a result of higher revenue 40


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from joint pole usage. In addition, $6 million of incremental revenues resulted from a combination of late fees, transmission resale, storm deferrals, and a variety of smaller miscellaneous items. 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. In 2019, Purchased power and fuel expense increased $43 million, or 8%, from 2018, which was driven by a $61 million increase that resulted from a higher average variable power cost per MWh, offset by a $18 million decrease related to total system load. The $61 million increase related to average variable power cost is due to an increase in cost per MWh from $25.31 in 2018 to $26.62 per MWh in 2019. The price increase was driven primarily by a 24% increase in the average variable power cost per MWh for purchased power as the Company, on average, purchased power at higher market prices. The average variable cost per MWh for PGE generating resources remained relatively flat from 2018 to 2019. Although total system load is up 2% from 2018, the $18 million decrease due to total system load was largely due to PGE effectively dispatching its lowest-cost resources in a challenged market, resulting in a 14% increase in energy generated by PGE resource.

In 2019, energy received from Biglow Canyon and Tucannon River decreased 9% from 2018 due to less favorable wind conditions and provided 9% of the Company's retail load requirement in 2019 compared with 10% in 2018.

As a result of the less favorable hydro conditions in the region for 2019, energy received from PGE-owned hydroelectric projects in combination with mid-Columbia projects was 20% below 2018 levels and represented 13% of the Company's retail load requirement for 2019 compared with 17% for 2018.

The following table presents the actual April-to-September 2019 and 2018 runoff at particular points of major rivers relevant to PGE's hydro resources:

Runoff as a

Percent of 30-year Average

2019 2018 Location Actual Actual Columbia River at The Dalles, Oregon 94 % 98 % Mid-Columbia River at Grand Coulee, Washington 87 99 Clackamas River at Estacada, Oregon 114 97 Deschutes River at Moody, Oregon 111 96 Actual NVPC, which consists of Purchased power and fuel expense net of Wholesale revenues, increased $32 million in 2019 compared with 2018. The increase attributable to changes in Purchased power and fuel expense was the result of a 5% increase in the average variable power cost per MWh and a 2% increase in total system load. This was partially offset by a 9% increase in the volume of wholesale energy deliveries, that were sold, on average, at 1% lower average price per MWh. For 2019, actual NVPC, as calculated for regulatory purposes under the PCAM, was $5 million above the 2019 baseline NVPC. In 2018, NVPC was $3 million below the anticipated baseline. For further information regarding NVPC, see "Power Operations" in the Overview section of this Item 7. Generation, transmission, and distribution expense increased $31 million, or 11%, in 2019 compared with 2018. The increase was driven by $13 million higher distribution expenses for vegetation management, wildfire mitigation and preventative maintenance, $6 million higher expenses at the Company's generation facilities, $3 million higher transmission expenses and $9 million miscellaneous expenses. Administrative and other expense increased $19 million, or 7%, in 2019 compared with 2018, primarily due to $13 million higher overall labor and employee benefit expenses, a $10 million benefit from the Carty cash settlement that occurred in 2018 that did not recur in 2019, $5 million higher costs related to the new customer billing system (ongoing support in 2019 and 2018 deferral of costs, offset by collection in 2019), $6 million miscellaneous expenses, offset by an $11 million net year over year impact due to the change in retail customer collection experience following the implementation of the customer information system, and $4 million lower legal expenses attributable to the conclusion of the Carty litigation. Depreciation and amortization expense in 2019 increased $27 million, or 7%, compared with 2018. The increase was primarily driven by a $19 million increase in depreciation and amortization expense resulting from capital additions, an $8 million increase related to net regulatory deferrals and amortization activity (which is offset in revenues), a $4 million increase due to the new lease standard reflecting the amortization of Finance lease right of use assets, partially offset by a $4 million increase to non-utility AROs in 2018 that did not recur in 2019.

Taxes other than income taxes expense increased $5 million, or 4%, in 2019 compared with 2018, primarily due to higher Oregon property taxes.

Interest expense increased $4 million, or 3%, in 2019 compared with 2018 as a $6 million increase was due to the new lease standard reflecting interest associated with Finance lease obligations, which are offset in Revenues, net as costs are being recovered in the AUT. In addition, a $1 million increase resulted from higher interest on net regulatory liabilities and a $1 million increase from lower AFUDC as the result of lower construction work-in-progress balances. A $4 million decrease resulted from the maturity of $300 million and the early redemption of $50 million of FMBs that were replaced with lower rate debt, reducing the Company's weighted average cost of debt.

Other income, net increased $9 million compared to 2018, with the difference due to gains of $5 million related to the non-qualified employee benefit trust assets, a $2 million curtailment gain recognized in 2019 due to changes in retiree medical plans and $2 million lower pension costs due to changes in actuarial assumptions.

Income tax expense increased $10 million, or 59%, in 2019 compared to 2018 primarily due to a decrease in PTCs and higher pre-tax income.

2018 Compared to 2017

For a comparison of the Company's results of operations for the fiscal year ended December 31, 2018 to the year ended December 31, 2017, 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, 2018, filed with the SEC on February 15, 2019.

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 2019 and projected capital expenditures and future debt maturities for 2020 through 2024 (in millions, excluding AFDC):

Years Ending December 31, 2019 2020 2021 2022 2023 2024 Ongoing capital expenditures* $ 572 $ 675 $ 500 $ 500 $ 500 $ 500 Integrated Operations Center 27 95 80 - - - Wheatridge Renewable Energy Facility 17 120 15 - - - Total capital expenditures $ 616 $ 890 $ 595 $ 500 $ 500 $ 500 Long-term debt maturities $ 350 $ - $ 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 2019, PGE funded its capital requirements through a combination of cash from operations in the amount of $546 million and proceeds from the issuance of FMBs in the amount of $470 million. Capital requirements in 2020 are expected to be $890 million. PGE plans to fund the 2020 capital requirements with cash from operations during 2020, which is expected to range from $625 million to $675 million, the issuance of debt securities of up to $400 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 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.

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



Table of Contents Years Ended December 31, 2019 2018 Cash and cash equivalents, beginning of year $ 119 $ 39 Net cash provided by (used in): Operating activities 546 630 Investing activities (604 ) (471 ) Financing activities (31 ) (79 ) Net change in cash and cash equivalents (89 )


Cash and cash equivalents, end of year $ 30 $ 119

2019 Compared to 2018 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 $84 million decrease in cash flows from operating activities in 2019 compared to 2018 is due to: • $68 million decrease relating to TCJA as a deferral occurred in 2018 with

amortization recorded in 2019;

• $67 million decrease for Accounts payable and other accrued liabilities

partially due to decreased fuel costs from lower gas prices in the fourth

quarter 2019 compared to the fourth quarter 2018;

• $53 million decrease for an additional contribution to pension and other

postretirement benefits; partially offset by

• $59 million decrease as a result of changes in Accounts receivable and

Unbilled revenue balances;

• $27 million increase in Depreciation and amortization primarily due to

higher average plant balances;

• $23 million increase in Deferred income taxes primarily due to increased

contributions to pension and other postretirement benefits.

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 2020 will range from $415 million to $435 million. Combined with all other sources, cash provided by operations in 2020 is estimated to range from $625 million to $675 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 $133 million increase in net cash used in investing activities in 2019 compared with 2018 is primarily due to the $120 million cash inflow as a result of the Carty litigation settlement that occurred in 2018 that did not recur in 2019. The Company plans for $890 million of capital expenditures in 2020 related to upgrades to and replacement of generation, transmission, and distribution infrastructure. PGE plans to fund the 2020 capital expenditures with cash from operations during 2020, 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 2019, cash used in financing activities consisted primarily of the issuance of $470 million of long-term debt, less the repayment $350 million of FMBs and payment of dividends in the amount of $134 million. 42


Table of Contents 2018 Compared to 2017 For a comparison of liquidity and capital resources and the Company's cash flow activities for the fiscal year ended December 31, 2018 and 2017, 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, 2018, which was filed with the SEC on February 15, 2019.

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 Positive 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, 2019, PGE had posted $31 million of collateral with these counterparties, consisting of $16 million in cash and $15 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, 2019, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is $51 million and decreases to $4 million by December 31, 2020 and none by December 31, 2021. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is $132 million and decreases to $78 million by December 31, 2020 and $68 million by December 31, 2021. PGE's financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facilities would increase. The Indenture securing PGE's outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that on December 31, 2019, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to $937 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% of total capitalization (debt to total capital



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ratio). As of December 31, 2019, the Company's debt to total capital ratio, as calculated under the credit agreements, was 51.9%.

Debt and Equity Financings

PGE's ability to secure sufficient 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. Management believes that the availability of revolving credit facilities, the expected ability to issue 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. 44


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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 7, 2022. As of December 31, 2019, 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%, 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.

PGE classifies any 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, 2019, PGE had no borrowings or commercial paper outstanding, and no letters of credit issued. As a result, as of December 31, 2019, 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 can request letters of credit for original terms not to exceed one year. These facilities provide for a 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 $55 million were outstanding as of December 31, 2019. Long-term Debt-During 2019, PGE issued a total of $470 million of FMBs with $200 million issued in April at an interest rate of 4.3% maturing in 2049 and $270 million at an interest rate of 3.34% issued in two tranches. The first tranche, $110 million with a maturity in 2049, was issued in October 2019 and the second tranche, $160 million with a maturity in 2050, was issued in November 2019. A portion of the proceeds were used to repay a total of $350 million in FMBs in 2019.

As of December 31, 2019, total long-term debt outstanding, net of $11 million of unamortized debt expense, was $2,597 million, of which none is scheduled to mature in 2020.

Capital Structure-PGE's financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) 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 48.1% and 49.8% as of December 31, 2019 and 2018, respectively.

Contractual Obligations and Commercial Commitments

The following table presents PGE's contractual obligations as of December 31, 2019 (in millions): There- 2020 2021 2022 2023 2024 after Total Long-term debt $ - $ 160 $ - $ - $ 80 $ 2,368 $ 2,608 Interest on long-term debt (1) 119 117 115 115 115 1,887 2,468 Capital and other purchase commitments 393 130 14 4 1 56 598 Purchased power and fuel: Electricity purchases 193 189 220 219 215 2,327 3,363 Capacity contracts - 9 9 9 9 9 45 Public Utility Districts 16 15 13 13 12 50 119 Natural gas 59 45 40 38 42 603 827 Coal and transportation 27 27 27 27 27 27 162 Pension Plan Contributions (2) - - 9 27 30 - 66 Finance and operating lease obligations 24 24 24 22 21 281 396 Total $ 831 $ 716 $ 471 $ 474 $ 552 $ 7,608 $ 10,652 (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, 2019. (2) Contributions beyond 2024 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 the Wells 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: • PGE has four letter of credit facilities that provide capacity up to a total of $220 million under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters 45


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of credit is subject to the approval of the issuing institution. Under these facilities, $55 million has been issued as of December 31, 2019; and • As a co-owner of Colstrip, PGE has provided surety bonds of $18 million as

of December 31, 2019 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 currently anticipated 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

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. Changes that may arise over time with regard to these assumptions and determinations can change future amounts recorded for AROs. 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. Accretion of the ARO liability is classified as a Depreciation and amortization expense in the consolidated statements of income. 46


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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.


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.


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