
Level 1			Quoted prices are available in active markets for identical assets or liabilities as of the measurement ~~date.~~

	date;
Level 2			Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement ~~date.~~

	date; and
Level 3			Pricing inputs include significant inputs that are unobservable for the asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of ~~fair value~~ assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value ~~hierarchy; instead these~~hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

Table of Contents

~~PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments.~~

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. ~~There~~

The Company’s financial assets and liabilities whose values were ~~no significant transfers between levels during~~recognized at fair value in the ~~three~~Company’s condensed consolidated balance sheets are as follows by level within the fair value hierarchy (in millions):


	As of March 31, 2024
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	173	$	—	$	—	$	—	$	173
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	8		8		—		—		16
Corporate credit	—		7		—		—		7
Money market funds	—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	2		—		—		—		2





Paid Leave Oregon Trust
Money market funds	—		—		—		3		3
Price risk management activities: (1) (4)
Electricity	—		20		6		—		26
Natural gas	—		11		—		—		11
	$	186	$	46	$	6	$	10	$	248
Liabilities:

Price risk management activities: (1) (4)
Electricity	$	—	$	28	$	33	$	—	$	61
Natural gas	—		116		16		—		132
	$	—	$	144	$	49	$	—	$	193

(1)Activities are subject to regulation, with certain gains and ~~nine month periods ended September 30, 2017~~losses deferred pursuant to regulatory accounting and ~~2016, except those presented~~included in ~~this note.~~Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $31 million, which are recorded at cash surrender value.

(4)For further information, see Note 5, Risk Management.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)


	As of December 31, 2023
	Level 1		Level 2		Level 3		Other (2)		Total
Assets:
Cash equivalents	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning trust: (1)

Debt securities:
Domestic government	9		9		—		—		18
Corporate credit	—		7		—		—		7
Money market funds	—		—		—		6		6
Non-qualified benefit plan trust: (3)
Debt securities—domestic government	3		—		—		—		3
Money market funds	2		—		—		—		2




Paid Leave Oregon Trust:
Money market funds	—		—		—		3		3
Price risk management activities: (1) (4)
Electricity	—		8		14		—		22
Natural gas	—		11		—		—		11
	$	14	$	35	$	14	$	9	$	72
Liabilities:

Price risk management activities: (1) (4)
Electricity	$	—	$	30	$	43	$	—	$	73
Natural gas	—		150		16		—		166
	$	—	$	180	$	59	$	—	$	239

~~The Company’s financial~~

(1)Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

(2)Assets are measured at NAV as a practical expedient and ~~liabilities whose values were recognized~~not subject to hierarchy level classification disclosure.

(3)Excludes insurance policies of $30 million, which are recorded at ~~fair~~cash surrender value.

(4)For further information, see Note 5, Risk Management.

Cash equivalents arehighly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted average maturity of securities holdings of such funds not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. Cash equivalents are classified as ~~follows by level within~~Level 1 in the fair value hierarchy ~~(in millions):~~due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for money market fund prices include published exchanges such as the National Association of Securities Dealers Automated Quotations (Nasdaq) and the New York Stock Exchange (NYSE).

As of September 30, 2017
Level 1 Level 2 Level 3
Other⁽²⁾
Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾

Debt securities:
Domestic government $ 3
$ 8
$ —
$ —
$ 11
Corporate credit —
7
—
—
7
Money market funds measured at NAV ⁽²⁾
—
—
—
23
23
Non-qualified benefit plan trust: ⁽³⁾

Money market funds 2
—
—
—
2
Equity securities—domestic 6
—
—
—
6
Debt securities—domestic government 1
—
—
—
1
Collective trust—domestic equity measured at NAV ⁽²⁾
—
—
—
—
—
Assets from price risk management activities: ^{(1) (4)}

Electricity —
3
—
—
3
Natural gas —
1
—
—
1
$ 12
$ 19
$ —
$ 23
$ 54
Liabilities from price risk management
activities: ^{(1) (4)}

Electricity $ —
$ 3
$ 140
$ —
$ 143
Natural gas —
37
13
—
50
$ —
$ 40
$ 153
$ —
$ 193


~~(1)~~	~~Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.~~


~~(2)~~	Assets ~~are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.~~


~~(3)~~	~~Excludes insurance policies of $28 million, which are recorded at cash surrender value.~~


~~(4)~~	~~For further information, see Note 4, Price Risk Management.~~

~~Table of Contents~~

~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

As of December 31, 2016
Level 1 Level 2 Level 3
Other ⁽²⁾
Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾

Debt securities:
Domestic government $ 2
$ 10
$ —
$ —
$ 12
Corporate credit —
8
—
—
8
Money market funds measured at NAV ⁽²⁾
—
—
—
21
21
Non-qualified benefit plan trust: ⁽³⁾

Money market funds 1
—
—
—
1
Equity securities—domestic 4
—
—
—
4
Debt securities—domestic government 1
—
—
—
1
Collective trust—domestic equity measured at NAV ⁽²⁾
—
—
—
2
2
Assets from price risk management activities: ^{(1) (4)}

Electricity —
6
1
—
7
Natural gas —
15
1
—
16
$ 8
$ 39
$ 2
$ 23
$ 72
Liabilities from price risk management
activities: ^{(1) (4)}

Electricity $ —
$ 6
$ 112
$ —
$ 118
Natural gas —
42
9
—
51
$ —
$ 48
$ 121
$ —
$ 169


~~(1)~~	~~Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.~~


~~(2)~~	~~Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.~~


~~(3)~~	~~Excludes insurance policies of $26 million, which are recorded at cash surrender value.~~


~~(4)~~	~~For further information, see Note 4, Price Risk Management.~~

~~Trust assets~~ held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan ~~(NQ Plan)~~(NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

Debt securities—PGE invests in highly-liquid United States ~~treasury~~Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

~~Table of Contents~~

~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

~~Equity securities~~—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

~~Common~~The NQBP trust is invested in exchange-traded government money market funds and ~~collective trust funds—PGE invests in common and collective trust funds that invest in equity securities. The Company believes the redemption value of these funds~~ is ~~likely to be the fair value, which is represented by the net asset value~~classified as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance to be paid after the annual fund audit is complete. Common and collective trusts are not classifiedLevel 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as ~~they are~~Nasdaq and the NYSE. The money market fund in the NDT is valued at NAV as a practical ~~expedient.~~expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, ~~are~~ recorded at fair value in PGE’s condensed consolidated balance sheets, ~~and~~ consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price ~~risk~~ and foreign currency exchange ~~rate risk,~~rates and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note ~~4, Price~~5, Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of ~~instruments~~longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. ~~These instruments consist of longer term commodity forwards, futures, and swaps.~~

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:


	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities				Low		High		Weighted Average
	(in millions)
As of March 31, 2024
Electricity physical forwards	$	5	$	32	Discounted cash flow	Electricity forward price (per MWh)	$	17.00	$	156.50	$	78.73
Natural gas financial swaps	—		16		Discounted cash flow	Natural gas forward price (per Decatherm)	2.28		9.59		3.40
Electricity financial futures	1		1		Discounted cash flow	Electricity forward price (per MWh)	40.00		156.50		92.51
	$	6	$	49
As of December 31, 2023
Electricity physical forwards	$	14	$	43	Discounted cash flow	Electricity forward price (per MWh)	$	37.53	$	153.33	$	84.58
Natural gas financial swaps	—		16		Discounted cash flow	Natural gas forward price (per Decatherm)	2.25		8.89		3.37
Electricity financial futures	—		—		Discounted cash flow	Electricity forward price (per MWh)	65.30		107.31		91.33
	$	14	$	59

Fair Value Valuation Technique Significant Unobservable Input Price per Unit
Commodity Contracts Assets Liabilities Low High Weighted Average
(in millions)
As of September 30, 2017:
Electricity physical forwards $ —
$ 140
Discounted cash flow Electricity forward price (per MWh) $ 8.20
$ 37.15
$ 28.36
Natural gas financial swaps —
13
Discounted cash flow Natural gas forward price (per Decatherm) 1.59
3.22
2.07
Electricity financial futures —
—
Discounted cash flow Electricity forward price (per MWh) 8.20
29.50
23.05
$ —
$ 153

As of December 31, 2016:
Electricity physical forwards $ —
$ 112
Discounted cash flow Electricity forward price (per MWh) $ 14.25
$ 54.73
$ 38.18
Natural gas financial swaps 1
9
Discounted cash flow Natural gas forward price (per Decatherm) 1.85
4.92
2.64
Electricity financial futures 1
—
Discounted cash flow Electricity forward price (per MWh) 8.57
33.60
25.10
$ 2
$ 121

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed long-term price curves ~~which derive longer term prices and~~that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. ~~In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.~~

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and PGE’s position as either the buyer or seller under thecontract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input

Position

~~Position~~

Change to Input

Impact on Fair Value ~~Measurement~~

Market price

Buy

~~Buy~~

Increase (decrease)

Gain (loss)

Market price

Sell

~~Sell~~

Increase (decrease)

Loss (gain)

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):


						Three Months Ended March 31,
						Three Months Ended March 31,
						Three Months Ended March 31,
								2024		2024	2023
Balance as of the beginning of the period
Net realized and unrealized losses/(gains)*

	Three Months Ended September 30,					Nine Months Ended September 30,
Transfers from Level 3 to Level 2
	2017			2016		2017		2016
Balance as of the beginning of the period	153			158		$	119	$	119
Net realized and unrealized (gains)/losses^*	(1		)	—		34		40
Transfers out of Level 3 to Level 2	1			2		—		1

Transfers from Level 3 to Level 2

Transfers from Level 3 to Level 2
Balance as of the end of the period	$	153		$	160	$	153	$	160

* Both realized and unrealized losses/(gains)~~/losses,~~, of which the unrealized ~~portion is fully~~portions are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income.

~~Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During~~ Includes$1 million and $5 million in net realized losses for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2024 and ~~2016, there were no transfers into Level 3 from Level 2.~~ 2023, respectively.

Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. ~~PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its derivative instruments.~~

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur, as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The ~~fair~~ value of the Company’s FMBs and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans was classified as a Level 3 fair value measurement and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.measurement.

As of ~~September 30, 2017~~,March 31, 2024, the carrying amount of PGE’s long-term debt was ~~$2,377~~$4,433 million, net of $9$15 million of unamortized debt expense, and its estimated aggregate fair value was ~~$2,763 million, consisting of$2,663 million and$100 millionclassified as Level 2 and Level 3, respectively, in the fair value hierarchy.~~

$3,955 million. As of December 31, ~~2016,~~2023, the carrying amount of PGE’s long-term debt was ~~$2,350~~$3,985 million, net of ~~$11~~$14 millionof unamortized debt expense, and its estimated aggregate fair value was ~~$2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.~~$3,705 million.

NOTE ~~4: PRICE~~5: RISK MANAGEMENT

PGE participates in the wholesale marketplace ~~in order~~ to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer ~~its existing~~the Company’s long-term wholesale contracts. ~~Such activities~~Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions ~~for~~with respect to Company-owned generation resources. The Company also performs portfolio management and wholesale market services for third parties in the region. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from

~~Table of Contents~~

~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign ~~currency~~exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments, ~~may include forward, futures, swaps, and option contracts, which are~~ recorded at fair value on the condensed consolidated balance sheets, may include forwards, futures, swaps, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. In accordance with ~~the~~ ratemaking and cost recovery processes authorized by the ~~Public Utility Commission of Oregon (OPUC), the Company~~OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative ~~instruments~~activity until settlement of the associated derivative instrument. ~~PGE~~The Company may designate certain derivative instruments as cash flow hedges or may use derivative ~~instruments~~instruments as economic hedges. ~~The Company~~PGE does not intend to engage in trading activities for non-retail purposes.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):


	March 31, 2024		December 31, 2023
Current assets:
Commodity contracts:
Electricity	$	20	$	13
Natural gas	9		9
Total current derivative assets (1)	29		22
Noncurrent assets:
Commodity contracts:
Electricity	6		9
Natural gas	2		2
Total noncurrent derivative assets (1)	8		11

Total derivative assets (2)	$	37	$	33
Current liabilities:
Commodity contracts:
Electricity	$	44	$	51
Natural gas	93		113
Total current derivative liabilities	137		164
Noncurrent liabilities:
Commodity contracts:
Electricity	17		22
Natural gas	39		53
Total noncurrent derivative liabilities	56		75

Total derivative liabilities (2)	$	193	$	239

September 30, 2017 December 31,
2016
Current assets:
Commodity contracts:
Electricity $ 3
$ 6

Natural gas 1
12

Total current derivative assets 4
⁽¹⁾
18
⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity —
1

Natural gas —
4

Total noncurrent derivative assets —
5
⁽²⁾
Total derivative assets not designated as hedging instruments $ 4
$ 23

Total derivative assets $ 4
$ 23

Current liabilities:
Commodity contracts:
Electricity $ 11
$ 12

Natural gas 32
32

Total current derivative liabilities 43
44

Noncurrent liabilities:
Commodity contracts:
Electricity 132
106

Natural gas 18
19

Total noncurrent derivative liabilities 150
125

Total derivative liabilities not designated as hedging instruments $ 193
$ 169

Total derivative liabilities $ 193
$ 169

(1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets.


~~(1)~~	~~Included in Other current assets on the condensed consolidated balance sheets.~~


~~(2)~~	~~Included in Other noncurrent assets on the condensed consolidated balance sheets.~~

(2) As of March 31, 2024 and December 31, 2023, no derivative assets or liabilities were designated as hedging instruments.

PGE’s net ~~purchase~~ volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions):


	March 31, 2024			December 31, 2023
Commodity contracts:
Electricity	4		MWhs	3		MWhs
Natural gas	200		Decatherms	213		Decatherms

Foreign currency	$	22	Canadian	$	20	Canadian

~~Table of Contents~~

~~PORTLAND GENERAL ELECTRIC COMPANY~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~(Unaudited)~~

September 30, 2017 December 31, 2016
Commodity contracts:
Electricity 6
MWh 8
MWh
Natural gas 114
Decatherms 107
Decatherms
Foreign currency $ 21
Canadian $ 22
Canadian

PGE has elected to report ~~gross on the condensed consolidated balance sheets the~~ positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting ~~arrangement.~~arrangement gross on the condensed consolidated balance sheets. In the case of default on, or termination of, any contract under the master netting arrangements, ~~these~~such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of ~~September 30, 2017, and December~~March 31, ~~2016,~~2024, gross amounts included as Price risk management liabilities subject to master netting agreements were ~~$143~~$24 million, comprised of $21 million for natural gas and ~~$115~~$3 million ~~respectively,~~for electricity, for which PGE has posted ~~collateral of $11 million, which consisted entirely of letters of credit.~~no collateral. As of ~~September 30, 2017,~~December 31, 2023, gross amounts included as Price risk

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

management liabilities subject to master netting agreements were $28 million, for which PGE had posted $1 million collateral. Of the gross amounts recognized ~~$140~~as of December 31, 2023, $3 million was for electricity and $3$25 million was for natural ~~gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, 2016.~~gas.

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions):


	Three Months Ended March 31,
		2024		2023
Commodity contracts:
Electricity		$	(19)	$	(35)
Natural Gas		14		132

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Commodity contracts:
Electricity $ 1
$ 8
$ 50
$ 60
Natural Gas 7
10
48
(14 )
Foreign currency exchange —
—
(1 ) (1 )

Net unrealized and certain net realized ~~losses~~ losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. ~~None of~~Of the net ~~losses~~amounts recognized in Net income for the ~~three month period~~three-month periods ended ~~September 30, 2017 was offset, while~~March 31, 2024 and 2023, net gains of$49 million and net losses of ~~$20~~$206 million, ~~were offset for the three month period ended September 30, 2016. Net losses of $65 million and $36 million~~respectively, have been ~~offset for the nine month periods ended September 30, 2017 and 2016, respectively.~~offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized ~~loss~~loss/(gain) recorded as of ~~September 30, 2017~~March 31, 2024 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):


	2024		2025		2026		2027		2028		Thereafter		Total
Commodity contracts:
Electricity	$	17	$	19	$	(1)	$	(1)	$	—	$	1	$	35
Natural gas	76		29		15		1		—		—		121
Net unrealized loss/(gain)	$	93	$	48	$	14	$	—	$	—	$	1	$	156

2017 2018 2019 2020 2021 Thereafter Total
Commodity contracts:
Electricity $ —
$ 9
$ 8
$ 8
$ 8
$ 107
$ 140
Natural gas 14
22
9
4
—
—
49
Net unrealized loss $ 14
$ 31
$ 17
$ 12
$ 8
$ 107
$ 189

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s ~~and/~~or S&P reduce their rating on ~~PGE’s~~the Company’s unsecured debt to below

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investment grade, ~~the Company~~PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of ~~September 30, 2017~~March 31, 2024 was ~~$191~~$177 million, for which PGE has posted ~~$18~~$65 million in collateral, consisting ~~entirely~~of $20 million of letters of ~~credit.~~credit and $45 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at ~~September 30, 2017,~~March 31, 2024, the cash requirement to either post as collateral or settle the instruments immediately would have been ~~$190~~$117 million. As of March 31, 2024, PGE had$6 million cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified asMargin deposits included in Other current assets on the Company’s condensed consolidated balance ~~sheet.~~sheets.

~~Counterparties representing 10% or more~~As of ~~Assets~~March 31, 2024, PGE held from counterparties$10 million in collateral, consisting of $5 million of letters of credit and ~~Liabilities from~~$5 million of cash. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets.

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PGE is exposed to credit risk in its commodity price risk management activities ~~were as follows:~~

September 30, 2017 December 31,
2016
Assets from price risk management activities:
Counterparty A 53 % 22 %
Counterparty B 3
17
Counterparty C 1
12
Counterparty D 15
— %
Counterparty E 10
— %
82 % 51 %
Liabilities from price risk management activities:
Counterparty F 72 % 66 %
72 % 66 %

related to potential nonperformance by counterparties. Credit risk may be concentrated to the extent the Company’s counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. PGE 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. The Company 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.

See Note 3,4, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

NOTE 5:6: EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ~~and~~ ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent ~~rights.~~rights; and iii) shares issuable pursuant to the at the market offering program. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

For the three ~~and nine month periods~~months ended ~~September 30, 2017,~~March 31, 2024, unvested performance-based restricted stock units and related dividend equivalent rights ~~in the total amount~~ of ~~267~~507 thousandshares were excluded from the dilutive calculation because the performance goals had not been met, with ~~306~~413 thousand shares excluded for the three ~~and nine month periods~~months ended ~~September 30, 2016.~~March 31, 2023.

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Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):


	Three Months Ended March 31,
		2024	2023
Weighted-average common shares outstanding—basic		101,299	91,840
Dilutive effect of potential common shares *		168	731
Weighted-average common shares outstanding—diluted		101,467	92,571

* As of March 31, 2023, 577,479 incremental shares were included in the calculation of diluted EPS related to the securities under the EFSA. There was no dilutive impact from the EFSA in 2024 as it was settled in July 2023.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Weighted-average common shares outstanding—basic and diluted 89,065
88,921
89,044
88,885

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NOTE 6:7: SHAREHOLDERS’ EQUITY

The activity in equity during the ~~nine months~~three-month periods ended ~~September 30, 2017~~March 31, 2024 and ~~2016~~ is2023 was as follows (dollars in ~~millions)~~millions, except per share amounts):


	Common Stock			Accumulated Other Comprehensive Loss		Retained Earnings

	Shares	Amount						Total
Balances as of December 31, 2023	101,159,609	$	1,750	$	(5)	$	1,574	$	3,319
Issuances of shares pursuant to equity-based plans	148,926	—		—		—		—
Issuances of shares pursuant to equity agreements	1,714,972	78		—		—		78



Dividends declared ($0.4750 per share)	—	—		—		(48)		(48)
Net income	—	—		—		109		109
Other comprehensive income	—	—		1		—		1
Balances as of March 31, 2024	103,023,507	$	1,828	$	(4)	$	1,635	$	3,459























Balances as of December 31, 2022	89,283,353	$	1,249	$	(4)	$	1,534	$	2,779
Issuances of shares pursuant to equity-based plans	159,603	—		—		—		—


Issuances of shares pursuant to equity agreements	7,178,016	300		—		—		300
Stock-based compensation	—	(1)		—		—		(1)
Dividends declared ($0.4525 per share)	—	—		—		(40)		(40)
Net income	—	—		—		74		74
Balances as of March 31, 2023	96,620,972	$	1,548	$	(4)	$	1,568	$	3,112

Common Stock
Accumulated
Other
Comprehensive
Loss

Retained
Earnings

Shares Amount Total
Balances as of December 31, 2016 88,946,704
$ 1,201
$ (7 ) $ 1,150
$ 2,344
Issuances of shares pursuant to equity-based plans 145,251
1
—
—
1
Stock-based compensation —
2
—
—
2
Dividends declared —
—
—
(90 ) (90 )
Net income —
—
—
145
145
Balances as of September 30, 2017 89,091,955
$ 1,204
$ (7 ) $ 1,205
$ 2,402

Balances as of December 31, 2015 88,792,751
$ 1,196
$ (8 ) $ 1,070
$ 2,258
Issuances of shares pursuant to equity-based plans 133,875
1
—
—
1
Stock-based compensation —
2
—
—
2
Dividends declared —
—
—
(84 ) (84 )
Other comprehensive income —
1
—
1
Net income —
—
—
132
132
Balances as of September 30, 2016 88,926,626
$ 1,199
$ (7 ) $ 1,118
$ 2,310

At-the-Market Offering Program—On April 28, 2023, PGE entered into an equity distribution agreement under which it could sell up to $300 million of its common stock through at the market offering programs. In 2023, pursuant to the terms of the equity distribution agreement, PGE entered into separate forward sale agreements with forward counterparties. In March 2024, the Company issued 1,714,972 shares pursuant to the agreements and received net proceeds of $78 million, settling all forward sale agreements in place. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

NOTE 7:8: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed consolidated financial statements are prepared. Legal costs incurred in connection with loss

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contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a

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reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired, or a liability incurred, if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be ~~determined,~~reasonably estimated, then ~~the Company:~~PGE: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the ~~reasons.~~reasons why the estimate cannot be made.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting ~~period.~~period, depending on the nature of the underlying event.

~~The Company~~PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, ~~will~~would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there ismay be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

~~Carty~~

In 2013, PGE entered into an agreement (Construction Agreement) with an engineering, procurement, and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (collectively, the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

In December 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed.

Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved cost of $514 million. Actual costs for the construction of Carty exceeded the approved amount and, as of September 30, 2017, PGE has capitalized $637 million to Electric utility plant.

As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. These incremental expenses are

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~~recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP.~~

Actual costs do not reflect any offsetting amounts that may be received from the Sureties, pursuant to the Performance Bond. The amounts recorded also exclude $8 million of liens and claims filed for goods and services provided under contracts with the former Contractor that remain in dispute. The Company believes these liens are invalid and is contesting the claims in the courts.

The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, correcting latent defects in work performed by the former Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials.

Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage that resulted from poor storage and maintenance on the part of the former Contractor.

The Company is involved in several litigation proceedings concerning the termination of the construction agreement and the payment obligations of the Sureties. PGE is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the contractor and claims against the Sureties pursuant to the performance bond. The Sureties have denied liability in whole under the Performance Bond.

Various actions relating to this matter have been filed in the U.S. District Court for the District of Oregon (U.S. District Court), in the Ninth Circuit Court of Appeals (Ninth Circuit), and in an arbitration proceeding before the International Chamber of Commerce International Court of Arbitration (ICC arbitration), involving the following:

A breach of contract claim brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract;

~~A claim brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement;~~

A claim by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and did not give rise to any liability of Abengoa S.A.; and

A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement and $44 million based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals.

Following various procedural arguments in the ICC arbitration and the U.S. District Court, in July 2017, the Ninth Circuit held that the ICC arbitration had jurisdiction to determine what parties and what claims could be presented in the ICC arbitration. Oral argument before the ICC arbitration is expected to take place in the spring of 2018. The decision of the ICC arbitration is expected to determine the forum in which the above referenced claims will be heard. Further detail on the various proceedings is presented in ~~Item1. Legal Proceedings~~ ~~in Part II - Other Information, of this Quarterly Report on Form 10-Q.~~

In July 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that

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such amounts are approved in a subsequent regulatory proceeding. The Company has requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved.

Any amounts approved by the OPUC for recovery under the deferral filing 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. The Company believes that costs incurred to date and capitalized in Electric utility plant, net, in the condensed consolidated balance sheet, were prudently incurred. There have been no settlement discussions with regulators related to such costs.

After exhausting all remedies against the aforementioned parties, the Company intends to seek approval to recover any remaining excess amounts in customer prices in a subsequent regulatory proceeding. However, there is no assurance that such recovery would be allowed by the OPUC.

In accordance with GAAP and the Company’s accounting policies, any such excess costs may be charged to expense at the time recovery becomes less than probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood is less than probable that a portion of the cost of Carty will be disallowed for recovery in customer prices. Accordingly, no loss has been recorded to date related to the project.

EPA Investigation of Portland Harbor

~~A 1997~~An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund ~~site and listed 69~~site. PGE has been included among more than one hundred Potentially Responsible Parties (PRPs)~~. PGE was included among the PRPs~~, as it ~~has~~ historically owned or operated property near the river. In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over 100.

~~The~~A Portland Harbor site remedial investigation ~~(RI) has been~~was completed pursuant to an ~~Administrative Order on Consent~~agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which ~~does~~did not include PGE. The LWG ~~has~~ funded the RIremedial investigation and feasibility study ~~(FS)~~ and ~~has~~ stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA ~~has~~ finalized ~~the FS,~~a feasibility study, along with the ~~RI,~~remedial investigation, and ~~these documents~~the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued ~~on January 6,~~in 2017. The ROD ~~outlines~~outlined the EPA’s selected remediation ~~alternative to~~plan for clean-up ~~for~~of Portland Harbor ~~which has~~that had an undiscounted estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance ~~costs, for a combined discounted present value of $1.05 billion. As stated within the ROD, such cost ranges were estimated with accuracy between -30% and +50% of actual~~ costs. Remediation construction costs ~~are~~were estimated to be incurred over a ~~13 year~~13-year period, with long-term operation and maintenance costs estimated to be incurred over a ~~30 year~~30-year period from the start of construction. Stakeholders have raised concerns that the EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The EPA ~~acknowledges~~acknowledged the estimated costs ~~are~~ were

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based on data that ~~is now~~was outdated and that ~~a period of~~ pre-remedial design sampling iswas necessary to gather updated baseline data to better refine the remedial design and estimated cost.

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially with the passage of time. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has ~~prepared~~indicated it will take the initial lead to perform remedial design on the remaining areas. The Company anticipates that remedial design costs will ultimately be allocated to PRPs as a ~~Draft Sampling Plan to encourage PRPs to enter into~~part of the allocation process for remediation costs of the EPA’s preferred remedy. The entirety of Portland Harbor continues under an ~~Administrative Order on Consent with the agency and begin the sampling process before the end of 2017.~~active engineering design phase.

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PGE ~~is participating~~continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including conclusion of remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE ~~cannot~~does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that ~~represents~~would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position.

~~Where damage~~In cases in which injuries to natural resources ~~has~~have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as ~~natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor~~ Natural Resource Damages ~~assessment (NRDA) process.~~(NRD). The EPA does not manage ~~NRDA~~NRD assessment activities but ~~provides~~does provide claims information and coordination support to the ~~Natural Resource Damages (NRD)~~NRD trustees. ~~Damage~~NRD assessment activities are typically conducted by a ~~Trustee~~ Council made up of the trustee entities for the site. The Portland Harbor NRD trustees ~~are~~consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon, and ~~certain tribal entities.~~the Nez Perce Tribe.

The NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore ~~damaged~~injured resources and may also compensate the trustees for costs incurred in assessing the damages. ~~The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. PGE believes that the Company’s~~PGE’s portion of ~~NRDA~~NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

~~As discussed above, significant uncertainties still remain concerning~~The impact of costs related to EPA and NRD liabilities on the ~~precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA,~~Company’s results of ~~resampling efforts, and the method of allocation of costs amongst PRPs. It~~operations is probable that PGE will share in a portion of these costs. However, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation ofmitigated by the Portland Harbor site, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

~~In July 2016, the Company filed a deferral application with~~Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC ~~seeking~~in 2017, the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allowPHERA allows the Company to defer estimated liabilities and recover incurred environmental expenditures related to Portland Harbor through a combination of third-party proceeds, ~~such as~~including but not limited to insurance recoveries, and, if necessary, through customer ~~prices, as necessary.~~prices. The mechanism ~~establishes~~established annual prudency reviews of environmental expenditures and isthird-party proceeds. Annual expenditures in excess of $6 million, excluding expenses related to contingent liabilities, are subject to an annual earnings ~~test.~~

~~Trojan Investment Recovery Class Actions~~

~~In 1993, PGE closed the Trojan nuclear power plant (Trojan)~~test and ~~sought full~~would be ineligible for recovery ~~of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on,~~ ~~87%~~ ~~of its remaining investment in Trojan.~~

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 2007, following several

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to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent GRC. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not collecting any Portland Harbor cost from the PHERA through customer prices.

~~appeals~~

Governmental Investigations

In March, April, and May 2021, the Division of Enforcement of the Commodity Futures Trading Commission (CFTC), the Division of Enforcement of the SEC, and the Division of Enforcement of the FERC, respectively, informed the Company they are conducting investigations arising out of the energy trading losses the Company previously announced in August 2020. The Company is cooperating with the CFTC, the SEC, and the FERC. Management cannot predict the eventual scope or outcome of these matters.

Colstrip-Related Litigation

The Company has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is located in the state of Montana and operated by ~~various~~one of the co-owners, Talen Montana, LLC (Talen). In May 2022, Talen’s parent company, Talen Energy Supply, LLC filed for chapter 11 bankruptcy protection, although Colstrip continues to operate and generate electricity for PGE customers and others. Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. An arbitration process has been initiated to address such business disagreements and, along with other matters related to Colstrip, are summarized below.

Arbitration—In March 2021, co-owner NorthWestern Corporation (NorthWestern) initiated arbitration against all other co-owners of Colstrip to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or, alternatively, whether unanimous consent is required. The O&O Agreement among the parties states that any dispute shall be submitted for resolution to a single arbitrator with appropriate expertise. The parties had agreed to stay the ~~Oregon~~arbitration through April 1, 2024 and are now in the process of reengaging in arbitration discussions. An arbitration date has not yet been scheduled. PGE cannot predict the ultimate outcome of the arbitration process.

Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al.—In December 2020, the original claim was filed in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from the defendants’ coal dust. In August 2021, the claim was amended to add PGE as a defendant. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court. This case is currently set for trial on November 5, 2024. The Company is unable to predict the outcome or estimate a range of any possible loss in this matter.

Westmoreland Mine Permits—Two lawsuits were commenced by the Montana Environmental Information Center, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine. This case was appealed and on November 22, 2023, the Supreme Court of ~~Appeals issued an opinion that remanded~~Montana reinstated the ~~matter to~~Montana District Court vacating the ~~OPUC for reconsideration.~~

In 2003, in two separate legal proceedings, lawsuits were filed in Marion County Circuit Court (Circuit Court) against PGE on behalf of two classes of electric service customers. The class action lawsuits seek damages totaling ~~$260 million, plus interest, as a result of~~permit and affirming the ~~Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.~~

In August 2006, the Oregon Supreme Court (OSC) issued a ruling ordering the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers. The OSC also ruled that the plaintiffs retained the rightlower court order to return to the ~~Circuit~~Board of Environmental Review for additional permit review considerations. In the second, the Montana Federal District Court issued findings and recommended that a decision approving expansion of the mine into a new area should be vacated, but recommended the decision not take effect for ~~disposition of whatever issues remained unresolved~~365 days from the ~~remanded OPUC proceedings. In October 2006,~~date of a final order. On November 24, 2023, the Ninth Circuit ~~Court abated the class actions in response to the ruling of the OSC.~~

~~In 2008, the OPUC issued an order that required PGE to provide refunds of $33 million, including interest, which refunds were completed in 2010. Following appeals, the order was upheld by the Oregon~~ Court of Appeals ~~in February 2013 and by the OSC in October 2014.~~

In June 2015, at PGE’s request, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed ~~all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. Briefing on~~ the appeal ~~is now complete, with a Court~~by Westmoreland for lack of ~~Appeals decision pending.~~

~~PGE believes~~appellate jurisdiction, and noted that the ~~October 2014 OSC decision and the recent Circuit Court decisions have reduced the risk of a loss~~appropriate venue to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain subject to a decision in the appeal, management believes that it is reasonably possible that such a loss in excess of amounts previously recorded could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.

~~Deschutes River Alliance Clean Water Act Claims~~

~~In August 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in~~raise issues will be the U.S. ~~District Court~~Office of Surface Mining during the District of Oregon. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

The SWW, located above Round Butte Dam, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters.

remand

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

~~In September 2016,~~process. PGE ~~filed~~is not a ~~motion~~party to ~~dismiss, which asserted that~~either of these proceedings, but is continuing to monitor the ~~CWA does not allow citizen suits~~progress of ~~this nature,~~both lawsuits and ~~that FERC has jurisdiction over all licensing issues, including~~assess the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion with the District Court for certification to file an interlocutory appeal with the Ninth Circuit and for a stayimpact, if any, of the ~~District Court proceeding. On April 7, 2017, the court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes)~~proceedings on Westmoreland’s ability to appear in the case as a friend of the court. The Tribes share ownership of the Project with PGE, but have not been named as a defendant. The District Court granted PGE’s request on May 19, 2017, but the Ninth Circuit denied the appeal on August 14, 2017. The parties are engaged in settlement discussions and filed a joint motion, which was granted September 11, 2017, to extend the stay of the District Court proceedings until either party finds the settlement negotiations unproductive.meet its contractual coal supply obligations.

The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material loss.

Other Matters

PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business that may result in judgments against the Company. Although management currently believes that resolution of such known matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

NOTE 8:9: GUARANTEES

PGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas ~~purchase and sale agreements~~ that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of ~~September 30, 2017,~~March 31, 2024, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 10: INCOME TAXES

Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income. The significant differences between the Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table:


	Three Months Ended March 31,
		2024		2023
Federal statutory tax rate		21.0	%	21.0	%
Federal tax credits*		(16.2)		(9.3)

State and local taxes, net of federal tax benefit		9.1		9.0
Flow-through depreciation and cost basis differences		0.2		1.0
Amortization of excess deferred income tax		(3.3)		(3.7)
Other		(0.1)		(2.1)
Effective tax rate		10.7	%	15.9	%

* Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. PTCs are earned based on a per-kilowatt hour rate and, as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s PTC generation will end at various dates through 2034.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Carryforwards

Federal tax credit carryforwards as of March 31, 2024 and December 31, 2023 were $94 million and $73 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2044. PGE included anticipated proceeds from the sale of tax credits in determining the need for a valuation allowance. PGE believes that it is more likely than not that its deferred income tax assets as of March 31, 2024 will be realized, however a valuation allowance has been recorded for the expected discount on the sale of tax credits. The valuation allowance as of March 31, 2024 was $1 million and was deferred as a regulatory asset. As of December 31, 2023, no material valuation allowance was recorded. As of March 31, 2024, and December 31, 2023, PGE had no material unrecognized tax benefits.



Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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,” “based on,” “conditioned upon,” “considers,” “could,” “expected,” “forecast,” “goals,” “needs,” “promises,” “subject to,” “targets,” 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 ~~forward-looking statements~~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

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parties, but there can be no assurance that ~~the~~PGE’s expectations, beliefs, or projections ~~contained in such forward-looking statements~~ will be achieved or accomplished.

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 such forward-looking statements include:

•governmental policies, legislative action, and regulatory audits, investigations, and actions, including those of the ~~FERC~~Federal Regulatory Energy Commission (FERC), the Public Utility Commission of Oregon, (OPUC), the United States Securities and Exchange Commission (SEC), and the ~~OPUC~~Division of Enforcement of the Commodity Futures Trading Commission (CFTC), with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs, operating expenses, deferrals, timely recovery of costs and capital investments, energy trading activities, and current or prospective wholesale and retail competition;

•economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers, and elevated levels of uncollectible customer accounts;

•inflation and volatility in interest rates;

•changing customer expectations and choices that may reduce customer demand for PGE’s services may impact the Company’s ability to make and recover its investments through rates and earn its authorized

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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 Electricity Service Suppliers (ESSs) or the adoption of community choice aggregation;

•the timing or outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Regulatory Matters of the “Overview” in this Item 2, and Note 7,8, Contingencies in the Notes to the Condensed Consolidated Financial ~~Statements;~~Statements in Item 1. Financial Statements of this Quarterly Report on Form 10-Q;

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

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

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

•unseasonable or severe weather and other natural phenomena, such as the greater size and prevalence of wildfires in Oregon in recent years, which could affect public safety, customers’ demand for power, and PGE’s ability and cost to procure adequate power and fuel supplies to serve its customers, ~~and could increase~~access the ~~Company’s costs to maintain~~wholesale energy market, or operate its generating facilities and transmission and distribution ~~systems;~~systems, and the Company’s costs to maintain, repair, and replace such facilities and systems, and recovery of such costs;

•PGE’s ability to effectively implement a public safety power shutoff (PSPS) and de-energize its system in the event of heightened wildfire risk or implement effective system hardening programs, the inability of which could lead to potential liability if energized systems are involved in wildfires that cause harm, as well as the risk that damages from wildfires may not be recoverable through rates or insurance, resulting in impact to the financial condition, results of operations, or reputation of the Company;

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

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

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

•delays in the supply chain and increased supply costs, failure to complete capital projects on schedule ~~and~~or within budget, inability to complete negotiations on contracts for capital projects, failure of counterparties to perform under agreements, or the abandonment of capital projects, ~~either~~any of which could result in the Company’s inability to recover project ~~costs;~~costs or impact PGE’s competitive position, market share, or results of operations in a material way;

•volatility in wholesale power and natural gas prices, ~~which~~including but not limited to volatility caused by macroeconomic and international issues, that could require PGE to post additional collateral or issue additional letters of credit ~~or post additional cash as collateral with counterparties~~ pursuant to power and natural gas purchase agreements;

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•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, volatility of equity markets 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;~~debt, and stock-based compensation plans, which are relied upon in part to retain key executives and employees;

•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, ~~and~~or industrial customer growth, ~~and~~or demographic patterns, including changes in ~~demographic patterns,~~load resulting in future transmission constraints, in PGE’s service territory;

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

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~~declines in the fair value of securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;~~

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, the ability to recruit and ~~employee retirements;~~retain key employees and other talent, and turnover due to macroeconomic trends such as voluntary resignation of large numbers of employees similar to that experienced by other employers and industries since the beginning of the COVID-19 pandemic;

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

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

•~~natural disasters~~social attitudes regarding the electric utility and power industries;

•political and economic conditions;

•the impact of widespread health developments and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other ~~risks such as earthquake, flood, drought, lightning, wind,~~restrictions on travel, commercial, social and ~~fire;~~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;

•risks and uncertainties related to current or future All-Source Request For Proposals (RFP) projects, including, but not limited to regulatory processes, legal actions, transmission capabilities, system interconnections, inflationary impacts, supply chain constraints, supply cost increases (including application of tariffs impacting solar module imports), permitting and construction delays, and legislative uncertainty; and

•acts of war or terrorism.

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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~~

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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. ~~This~~ MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report, ~~as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended~~ ~~December 31, 2016~~, and other periodic and current reports filed with the SEC.

PGE is a ~~vertically integrated~~vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity ~~as well as~~in the State. The Company participates in wholesale ~~purchase~~markets by purchasing and ~~sale of~~selling electricity and natural gas in ~~order~~an effort to meet the needs of, and obtain reasonably-priced power for, its retail customers, manage risk, and administer its long-term wholesale contracts. In addition, PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

Company Strategy

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

•Decarbonize Power—Reduce greenhouse gas (GHG) emissions associated with electricity served to retail customers by at least 80% by 2030 and 100% by 2040;

•Electrify the Economy—Increase beneficial electricity use to capture the benefits of new technologies while building an increasingly clean, flexible, and reliable grid; and

•Advance Performance—Improve safety, efficiency, and system and equipment reliability while maintaining affordable energy service and growing earnings per share 5% to 7% annually.

Climate Change

State-mandated GHG emissions reduction targets—In June 2021, the ~~fourth quarter~~Oregon legislature passed House Bill (HB) 2021, establishing a 100% clean electricity by 2040 framework for PGE and other investor-owned utilities and electric service suppliers in the State. A number of ~~2016,~~provisions in the bill align with PGE’s strategic direction and highlight Oregon’s ambitious, economy-wide goals to combat climate change. The GHG emissions reduction targets applicable to these regulated entities are an 80% reduction in GHG emissions by 2030, 90% by 2035, and 100% by 2040 and every year thereafter. For more information regarding HB 2021 and the baseline to which the target reductions apply, see “HB 2021” in the “Laws and Regulations” section of this Overview.

Empowering customers and communities—PGE’s customers have a desire for purchasing clean energy, as over 229 thousand residential and small commercial customers voluntarily participate in PGE’s Green Future Program, the largest renewable power program by participation in the nation. In 2017, Oregon’s most populous city, Portland, and most populous county, Multnomah, each passed resolutions to achieve 100% clean and renewable electricity by 2035 and 100 % economy-wide clean and renewable energy by 2050. Other jurisdictions in PGE’s service area have similar goals and continue to consider similar goals for the future.

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

As of March 31, 2024, the Green Future Impact Program has an approved capacity of 750 MW nameplate. Through this voluntary program, the Company seeks to support the customers’ clean energy acceleration, achieve PGE sustainability goals, mitigate cost and manage risk, and reliably integrate power.

The Climate Pledge—In 2021, PGE joined The Climate Pledge, a commitment to be net-zero annual carbon emissions by 2040, which is a decade ahead of the Paris Agreement’s goal of 2050. As a signatory to The Climate Pledge, PGE agrees to: i) measure and report GHG emissions on a regular basis; ii) implement decarbonization strategies in line with the Paris Agreement through real business changes and innovations, including efficiency improvements, renewable energy, materials reductions, and other carbon emission elimination strategies; and iii) neutralize any remaining emissions with additional, quantifiable, real, permanent, and socially-beneficial offsets.

Severe weather—In recent years, PGE’s territory has experienced unprecedented heat, historic ice and snowstorms, and wildfires. On January 13, 2024, the Company’s service territory encountered the first of a series of severe winter weather events, including snow, ice, and high winds that caused catastrophic damage to physical assets and resulted in widespread customer power outages. For more information regarding the January 2024 severe winter weather events, see “Declared States of Emergency” within this Overview section of this Item 2.August 2023 experienced a record-breaking heat wave with temperatures in the region reaching all-time recorded highs for the month. This resulted in a peak load demand of 4,498 MW, beating the Company’s previous all-time peak load demand, and surpassing the prior summer peak load by nearly 6%. The increase and severity of weather events highlights the importance of combating the effects of climate change through decarbonizing the power supply and investing in a more reliable and resilient grid.

Investing in a Clean Energy Future

The Resource Planning Process— PGE’s resource planning process includes working with customers, stakeholders, and regulators to chart the course toward a clean, affordable, and reliable energy future. With the passage of HB 2021, PGE created a Clean Energy Plan (CEP), which articulates the Company’s strategy to meet the 2030, 2035, and 2040 emission reduction targets through an equitable transition to a decarbonized grid. The CEP is based on, and was filed in connection with, the Company’s 2023 IRP. PGE filed its first combined IRP and CEP with the OPUC ~~its 2016 Integrated Resource Plan (IRP), which addresses the Company’s proposal to meet future customer demand~~in March 2023. That filing projected PGE’s resource and ~~describes PGE’s future energy supply strategy and anticipated resource~~capacity needs over the next 20 ~~years. The areas~~years and proposed an Action Plan to meet near-term needs, subject to the new HB 2021 emissions reduction requirements.

PGE estimates a total resource need of ~~focus~~approximately 3,500 to 4,500 MW of renewable energy and non-emitting capacity in order to meet the Company’s 2030 emissions reduction target. Through the 2021 All-Source RFP, PGE procured 311 MW of wind resources and 475 MW of capacity, leaving a remaining need to procure approximately 2,700 to 3,700 MW.

On January 25, 2024, the OPUC acknowledged PGE’s IRP, subject to certain conditions, providing regulatory support for the ~~plan, include, among other topics,~~Company to pursue the near-term resource additions articulated in the Action Plan. However, the OPUC declined to acknowledge the CEP, directing the Company to provide additional forecast of its emission reductions based on new analysis in the CEP/IRP Update to be filed in January 2025. PGE will continue to pursue its 2023 All-Source RFP while revising forecasts of emissions in the CEP

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2021 All-Source RFP

Pursuant to the 2021 All-Source RFP process, seeking approximately 1,000 MW of renewable resources ~~needed~~and non-emitting dispatchable capacity, PGE entered into agreements to acquire resources as follows:

•Clearwater Wind Development—PGE and NextEra Energy Resources, LLC, a subsidiary of NextEra Energy, Inc. entered into agreements to construct a 311 MW wind energy facility in Eastern Montana. PGE owns 208 MW of production capacity of the facility. Subsidiaries of NextEra Energy Resources, LLC, which operates the facility, owns the remaining 103 MW of production capacity and sells their portion of the output to PGE under a 30-year PPA. The project was placed in-service during the first quarter of 2024 with a total cost of $424 million, including AFUDC, as of March 31, 2024.

•Seaside Grid—PGE entered into an agreement to construct a 200 MW Battery Energy Storage System (BESS) in Portland, Oregon. PGE will own the resource, with an investment of approximately $360 million, excluding AFUDC. The project has an estimated commercial operation date of June 30, 2025. As of March 31, 2024, the Company has recorded $92 million, including AFUDC, in CWIP for the Seaside Grid.

•Constable BESS (formerly Evergreen)—PGE entered into an agreement to construct a 75 MW BESS in Hillsboro, Oregon. PGE will own the resource, with an investment of approximately $150 million, excluding AFUDC. The project has an estimated commercial operation date of December 31, 2024. As of March 31, 2024, the Company has recorded $48million, including AFUDC, in CWIP for the Constable BESS.

•Troutdale Grid—PGE entered into a storage capacity agreement for a 200 MW BESS in Troutdale, Oregon. NextEra Energy Resources, LLC, will own the resource and will sell the capacity to PGE under a 20-year storage capacity agreement. The project has an estimated commercial operation date of December 31, 2024.

The Clearwater agreements and all BESS agreements represent the final procurement from the 2021 All-Source RFP. Resources required to meet the remaining 2030 need are anticipated to be procured through future acquisition processes, including, but not limited to, the 2023 All-Source RFP and future RFPs.

All BESS projects will be directly interconnected to PGE’s system. Emissions associated with energy used to charge the BESS are accounted for when they are emitted from the generating facility. BESS projects do not add incremental emissions to the grid, and therefore, are non-emitting dispatchable capacity resources. The BESS projects will qualify for the federal investment tax credit (ITC). The Clearwater agreements will qualify for production tax credits (PTCs) and will be eligible under Oregon’s Renewable Portfolio Standard (RPS) ~~requirements and~~. The agreements will be subject to ~~replace energy from Boardman,~~prudency review by the ~~Company’s coal-fired generating plant located in Eastern Oregon that will cease coal-fired operations at the end of 2020. For further information regarding the IRP, see~~ ~~“Integrated Resource Plan”~~ ~~in this Overview section of Item 2.~~OPUC.

In February ~~2017,~~2022, NewSun Energy LLC (NewSun) filed a petition for judicial review in the Marion County Circuit Court against the OPUC challenging the scoring methodology in the 2021 All-Source RFP. PGE joined in the case as an intervenor. NewSun also filed a motion to stay the 2021 All-Source RFP process, which the Court subsequently denied. The OPUC filed a motion to dismiss the case and PGE joined the OPUC’s motion to dismiss. NewSun opposed the motion. In May 2022, the Court granted the motion to dismiss to which NewSun responded in June 2022 by filing a notice of appeal with the Court of Appeals of the State of Oregon. After receiving multiple extensions, NewSun filed its opening brief in the appeal in February 2023 and PGE filed a ~~general rate~~response brief in June 2023. In August 2023, PGE filed a notice asking the Court to dismiss the case. That motion remains pending. Oral argument in this case occurred March 18, 2024. The parties await a decision from the Court.

In October 2022, NewSun filed a petition in Deschutes County Circuit Court seeking review of the OPUC order acknowledging, with conditions, PGE’s 2021 All-Source RFP shortlist. PGE intervened in this case and, in March 2023, filed a motion to dismiss. In September 2023, the judge granted PGE’s motion to dismiss. In November 2023, NewSun filed a notice of appeal in the Court of Appeals of the State of Oregon. Opening briefs in the Appeal were filed March 1, 2024, with PGE to respond by May 9, 2024.

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PGE cannot predict the outcome of these proceedings or potential impact, if any, to its 2021 All-Source RFP process.

2023 All-Source RFP

PGE filed notice with the OPUC in January 2023 that an RFP in 2023 was needed to procure resources to meet a forecasted 2026 capacity shortfall and to make continued progress toward decarbonization targets under HB 2021. These actions were consistent with the 2023 IRP Action Plan and CEP. The filing included PGE’s request for a ~~2018 test year. Stipulations~~partial waiver of the OPUC’s competitive bidding rules, which was approved by the OPUC in April 2023, and outlined PGE’s recommended timeline for obtaining necessary regulatory approvals. PGE filed ~~on September 18, 2017~~the draft 2023 All-Source RFP with the OPUC in May 2023 and ~~October 9, 2017 reflect settlement of all issues.~~regulatory approval was granted in January 2024. The Company issued the RFP to market on February 2, 2024, seeking bids for resources that can provide non-emitting dispatchable capacity and renewable generation. The submission deadline for proposals is in April 2024. Bids will be evaluated based on the OPUC-approved scoring methodology. Following determination of a final shortlist, PGE plans to file for acknowledgement in mid-2024 with a final selection in the third or fourth quarter of 2024.

Transmission Upgrades

In alignment with local and regional transmission plans, the 2023 IRP Action Plan, and CEP, PGE is evaluating and implementing upgrades to existing transmission resources and expansions of current transmission networks. Transmission resource actions are intended to alleviate congestion, improve regional adequacy and reliability, enable decarbonization goals, and address growing customer demand.

Building a resilient grid—To serve communities with clean energy, PGE’s grid of the future will need to be smart and adaptive. Highlights of PGE’s key investments and plans for building a resilient grid include:

•Wildfire Mitigation—PGE has a Wildfire Mitigation Program under which an annual Wildfire Mitigation Plan (WMP) is developed and submitted to the OPUC to coordinate activities across the Company and with state-wide stakeholders. The 2024 WMP forecasts $45 million in operations and maintenance costs and an additional $43 to $49 million in capital investments in the current year to continue system hardening efforts, expand situational awareness capabilities, implement specific inspection and maintenance along with vegetation management, raise community and customer awareness, and take operational actions within high fire risk zones. PGE strives to improve regional safety by reducing the risk that the Company’s electric utility infrastructure could cause a wildfire, while limiting the impacts of PSPS events and other mitigation activities on customers and increasing the resiliency of PGE assets to wildfire damage. In the three months ended March 31, 2024, PGE invested $3 million in capital projects related to wildfire mitigation and resiliency and utility asset management, consistent with the 2024 WMP.

•Virtual Power Plant (VPP)—PGE’s VPP is a production resource comprised of Distributed Energy Resources (DERs) and flexible loads that are managed through technology platforms to provide grid and power operations services. PGE’s customer offerings related to energy efficiency and flexible load programs, rooftop solar, battery storage, and electric vehicle charging solutions support grid reliability and increase portfolio flexibility and resource diversity. These DERs and flexible loads are the foundation of PGE’s VPP that will provide a growing suite of grid and system services over time. When coordinated through the Company’s DER Management Systems, the various DERs and flexible loads support cost-effective decarbonization, advance customer and community energy resiliency, promote customer engagement with the energy system, and unlock additional grid services that enhance PGE’s operation of a dynamic two-way system. In 2023, PGE saw record energy demand of 4,498 MW on August 14. Customer actions that day, orchestrated through the VPP, reduced load by more than 90 MW, helping avoid customer service interruptions and reducing exposure to scarcity pricing in energy markets.

•Distribution System Plan—In 2021 and 2022, PGE filed its inaugural DSP in two parts, which were accepted by the OPUC in March 2022 and February 2023, respectively. While the OPUC Staff is in the

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process of reviewing whether to modify the current DSP guidelines, PGE plans to file its next DSP in the fourth quarter of 2024. The DSP outlines distribution system assets, describes how the Company plans for new load, including distributed resources such as electric vehicles (EVs) and Solar Photovoltaic installations, and presents the vision for modernizing the grid to enable accelerated decarbonization and customer participation in meeting PGE’s clean energy goals.

Electrify the economy—To help Oregon reach its decarbonization goals, PGE is working to build a safe, reliable, and affordable, economy-wide, clean energy future. The Company is committed to increasing electrification of buildings and supports the accelerating pace of vehicle electrification for our customers, as well as its own vehicle fleet.

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

In 2021, the Oregon legislature enacted HB 2165, ensuring the OPUC has clear and broad authority to allow electric company investments in infrastructure to support transportation electrification.

In 2023, PGE’s second Transportation Electrification (TE) plan was filed and accepted by the OPUC. This second TE plan considers current and planned activities, along with forecasted EV loads and potential system impacts. The 2023 TE plan represents a continuation of the approach and programmatic efforts found within PGE’s 2019 TE plan while also outlining the Company’s current strategy to integrate TE into utility business in order to plan, service, and manage EV load.

In the 2023 to 2025 period covered by the 2023 TE plan, capital expenditures are expected to be approximately $25 million. The final 2023 TE plan with its planned activities was accepted by the OPUC on October 17, 2023.

Businesses and families continue to turn to electricity to serve their home and workplace needs. PGE continues to pursue advanced technologies to enhance the grid, pursue distributed generation and energy storage, and develop microgrids and the use of data and analytics to better predict demand and support energy-saving customer programs.

Laws and Regulations

Federal Grants—In November 2021, the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA), which includes approximately $550 billion of new federal spending, was signed into law. PGE continues to pursue multiple areas under the IIJA, and other state, federal, and private programs, for potential grant funding of projects. These projects target improvements in electrical system reliability and resiliency, wildfire situational awareness and mitigation, greater communications capabilities, advancements in customer usage analytics using artificial intelligence, renewable resources and advanced electrical grid support, hydro generation operations, hydrogen production, utility workforce development, and regional transmission capacity constraints.

As of March 31, 2024, PGE has submitted 27 full federal grant applications and has been awarded 11 grants totaling $317.8 million, including the following:

•U.S. DOE Bethel-Round Butte Transmission Line Upgrade—The U.S. DOE selected the Confederated Tribes of Warm Springs (CTWS), in partnership with PGE, for a $250 million grant to upgrade the existing 230 kV Bethel-Round Butte Transmission line to 500 kV. The project will accelerate the development of transmission capacity, enabling new carbon-free generation in Central and Eastern Oregon to reach customer demand loads in Western Oregon. The added capacity and associated upgrades will also increase resiliency of the transmission system as well as resiliency of the CTWS Tribal communities by increasing

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resources available to the Tribes to support adaptation and response strategies. The U.S DOE and PGE are negotiating the final funding and scope for the line upgrade as part of a multi-year process.

•U.S. DOE Smart Grid Chip—The U.S. DOE selected a PGE led consortium for a $50 million grant for the Smart Grid Chip project. The project will enable real-time information at each meter to improve the visibility of the electrical system to grid operators, providing detection of potential operational problems and shorten outage times, ultimately helping to anticipate and mitigate the impacts of extreme weather on grid resiliency. The DOE and PGE are negotiating the final funding and scope for the line upgrade as part of a multi-year process.

PGE is in the process of assessing the impacts of these federal grants on the Company’s results of operations. Although PGE continues to apply for additional grants, the Company cannot predict the ultimate timing and success of securing funding from federal programs.

Inflation Reduction Act of 2022—The Inflation Reduction Act of 2022 (IRA) was signed into law in August 2022 with a majority of the provisions effective for tax years beginning after December 31, 2022.

The United States Treasury and the Internal Revenue Service released extensive rules addressing credit transfer eligibility and application, including but not limited to, required registration, filing, and documentation for transferors and transferees to elect and claim a credit transfer. On December 12, 2023, PGE received approval from the OPUC to transfer 2023 production tax credits and record any difference in the full value and the discounted value in a property balancing account. Consistent with options available under the IRA, PGE transferred 2023 credits with the final transfer occurring in the first quarter of 2024. On April 16, 2024, PGE received approval from the OPUC to transfer 2024 and 2025 PTCs and record any difference in the full value and the discounted value in a property balancing account. PGE has entered into an agreement to transfer 2024 and 2025 PTCs and expects to generate and transfer approximately $55 million in PTCs in 2024.

Compared to previous resource planning processes, the Company believes the new tax incentives will provide additional investment opportunities for PGE and result in lower customer prices. Increased capital expenditures in such investment opportunities would likely result in additional financing needs through debt and equity instruments.

HB 3143—In June 2023, the Oregon Legislature passed HB 3143, which was signed by the Governor on August 1, 2023. HB 3143 allows the OPUC to authorize ~~new customer prices effective January 1, 2018.~~the State’s investor-owned utilities, including PGE, to issue bonds and securitize debt for expenses associated with declared emergency events. The bill enables PGE, after a public process and rigorous review and approval by the OPUC, to issue, at a minimum, investment grade bonds to pay for the costs of declared emergencies.

HB 2021—In 2021, the Oregon Legislature passed HB 2021, which, among other things, requires retail electricity providers to reduce GHG emissions associated with serving Oregon retail electricity consumers 80% by 2030, 90% by 2035, and 100% by 2040, compared to baseline emissions levels. For ~~further information, see~~ ~~“General Rate Case”~~ PGE, the baseline levels are the average annual emissions for the years 2010, 2011, and 2012 associated with the electricity sold to its retail electricity consumers as reported to the Oregon Department of Environmental Quality (ODEQ).

HB 2021 requires utilities to develop a CEP for meeting the targets, concurrent with each IRP, that results in ~~this Overview section of Item 2.~~

~~On October 1, 2017,~~an affordable, reliable, and clean electric system. In reviewing a CEP, the ~~Company began active participation~~OPUC must ensure that utilities create a plan that is in the ~~Western Energy Imbalance Market (EIM). As a market participant, PGE’s generating plants now receive automated dispatch signals from~~public interest, demonstrate continual progress toward meeting the ~~California Independent System Operator~~targets, and take actions as soon as practicable that ~~allows~~facilitate rapid reduction of GHG emissions.

Under the law, retail electricity providers utilize the existing, required, annual reporting of GHG emissions to the ODEQ. In the target years of 2030, 2035, and 2040, and every year thereafter in the target period, the OPUC will use the data reported to the ODEQ for ~~load balancing with other EIM participants in five-minute intervals, which~~that compliance year to determine whether the ~~Company expects will help integrate more renewable energy into the grid by better matching the variable~~reduction targets are met.

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~~output~~RPS standards and other laws—In 2016, Oregon Senate Bill (SB) 1547 increased the 2007 benchmarks for the percentage of electricity that must come from renewable ~~resources. Additionally, this gives~~ sources by dates certain and required the elimination of coal as a fuel for generation of electricity used to serve Oregon utility customers no later than 2030.

PGE ~~access to~~ceased coal fired operation at its Boardman generating facility (Boardman) in 2020 and decommissioning of the ~~least-cost energy available in the region to meet changes in real-time energy demand and short-term variations in customer demand.~~

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.

~~Capital Requirements and Financing~~—plant is substantially complete. The Company ~~expects 2017 capital expenditures to total $533 million, excluding AFDC. For additional information regarding estimated capital expenditures, see “Capital Requirements~~”has a 20% ownership share in ~~the Liquidity and Capital Resources section of this Item 2.~~

PGE plans to fund capital requirements and maturities of long-term debt during the year of $150 million with cash from operations during 2017, which is expected to range from $515 million to $565 million, and the issuance of debt securities of $225 million. For additional information, see ~~“Liquidity”~~ ~~and~~ ~~“Debt and Equity Financings”~~ ~~in the Liquidity and Capital Resources section of this Item 2.~~

~~General Rate Case~~—On February 28, 2017, the Company filed with the OPUC a general rate case based on a 2018 test year (2018 GRC). The filing includes investments to ensure system safety and reliability and to better meet customers’ changing needs and service expectations. PGE’s initial filing proposed a $100 million increase in the annual revenue requirement related primarily to an increase in base business costs for upgrades to PGE’s transmission and distribution system, investments in strengthening and safeguarding the grid, and support for key initiatives such as participation in the Western Energy Imbalance Market (EIM). The proposal was based upon:

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

~~A return on equity of 9.75%; and~~

~~A rate base of $4.6 billion.~~

~~PGE, OPUC staff, and certain customer groups have reached agreements that resolve all issues in the case, provide for an expected $20 million net increase in annual revenue requirements, and reflect:~~

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

~~A return on equity of 9.5%; and~~

~~A rate base of $4.5 billion.~~

~~The net increase in annual revenue requirement as proposed in the Company’s initial filing and as revised consists of the following (in millions):~~

As Filed February 28, 2017 $ 100
Load and Power Cost Updates (28 )
Depreciation Study Updates (8 )
Base Business Revenue Requirement Updates:
     Lower return on equity $ (10 )
     Lower labor costs (9 )
     Adjustment to depreciation expense (8 )
     Lower level of plant in service (5 )
     Other reductions to rate base (4 )
     Other various modifications (8 )

          Subtotal (44 )
As Stipulated
$ 20

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Regulatory review of the 2018 GRC will continue until the final order is issued, which is expected in December 2017, with new customer prices expected to become effective January 1, 2018. Final revenue requirement amounts subject to revision include power costs (to be finalized November 2017) and actual cost of debt, including any additional debt issuances. Any subsequent reductions in PGE's overall cost of long-term debt through June 30, 2018 will be reflected either in the final 2018 GRC update or through a supplemental tariff filing. All stipulations remain subject to OPUC approval.

~~The 2018 GRC filing (OPUC Docket UE 319), as well as copies of direct and reply testimony, exhibits, and stipulations are available on the OPUC website at www.oregon.gov/puc.~~

~~Operating Activities—~~The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues and income from operations to fluctuate from period to period. PGE typically experiences its highest average MWh deliveries and retail energy sales during the winter heating season, although deliveries also increase during the summer months, generally resulting from air conditioning demand. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while 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 5.9% increase in retail energy deliveries for the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 resulted from increases in all retail categories with the greatest percentage increase in residential deliveries, which are most sensitive to fluctuations in weather.

Energy deliveries to residential customers increased 10.4% due in large part to the effects of cooler temperatures during the heating season and warmer temperatures during the cooling season, as well as customer growth of 1.3%. Energy deliveries to industrial customers increased 5.1%, largely due to continued strength in the high tech sector. Weather adjusted deliveries increased 0.3% from the first nine months of 2016 reflecting strength in the industrial sector. One additional day in 2016 due to leap year resulted in a comparative decrease of 0.4% in retail energy deliveries. Energy efficiency and conservation efforts by retail customers also influence demand, although the financial effects of such efforts by residential and certain commercial customers are mitigated by the decoupling mechanism. See ~~“Legal, Regulatory and Environmental”~~ ~~in this Overview section of Item 2 for further information on the decoupling mechanism.~~

During the third quarter of 2017, cooling degree-days, an indication of the extent to which customers are likely to have used electricity for cooling, were 45% above the third quarter of 2016. Residential energy deliveries, which are most weather sensitive, were 12.3% higher in the third quarter of 2017 than the third quarter of 2016. Unseasonably warm weather in first quarter of 2016, which decreased energy deliveries in that quarter, and temperatures that resulted in more heating and cooling degree days in the second quarter of 2017 also contributed to the increased deliveries on a year-to-date basis. See ~~“Revenues”~~ ~~in the Results of Operations section of this Item 2 for further information on heating degree days.~~

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The following table, which also includes deliveries to the Company’s direct access customers who purchase their energy from Electricity Service Suppliers, presents the average number of retail customers by customer type, and the corresponding energy deliveries, for the periods indicated:

Nine Months Ended September 30,
2017 2016
% Increase (Decrease) in Energy
Deliveries

Average
Number of
Customers

Retail Energy
Deliveries*

Average
Number of
Customers

Retail Energy
Deliveries*

Residential 761,028
5,826
751,198
5,278
10.4 %

Commercial (PGE sales only) 107,296
5,193
106,458
5,148
0.9 %
     Direct Access 479
472
314
403
17.1 %
Total Commercial 107,775
5,665
106,772
5,551
2.1 %

Industrial (PGE sales only) 198
2,187
193
2,168
0.9 %
     Direct Access 68
1,046
63
907
15.3 %
Total Industrial 266
3,233
256
3,075
5.1 %

Total (PGE sales only) 868,522
13,206
857,849
12,594
4.9 %
     Total Direct Access 547
1,518
377
1,310
15.9 %
Total 869,069
14,724
858,226
13,904
5.9 %


*	~~In thousands of MWh.~~

The Company’s Retail Customer Choice Program caps participation by Direct Access customers in the fixed three-year and minimum five-year opt-out programs, which account for the majority of energy supplied to Direct Access customers. This cap would have limited energy deliveries to these customers to an amount equal to approximately 13% of PGE’s total retail energy deliveries for the first nine months of 2017. Energy deliveries to Direct Access customers represented 9% of the Company’s total retail energy deliveries for the full year 2016, compared with 10% in the first nine months of 2017.

~~Power Operations~~—To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and power purchases in the wholesale market. In an effort to obtain reasonably-priced power for its retail customers, PGE makes economic dispatch decisions based on numerous factors including plant availability, customer demand, river flows, wind conditions, and current wholesale prices.

PGE’s generating plants require varying levels of annual maintenance, during which the respective plants are unavailable to provide power. As a result, the amount of power generated to meet the Company’s retail load requirement can vary from period to period. Plant availability, which is affected by both planned and unplanned outages, approximated 90% and 94% during the nine months ended September 30, 2017 and 2016, respectively, for those plants PGE operates. Plant availability of Colstrip Units 3 and 4 coal-fired generation plant (Colstrip) and, in response to SB 1547 has accelerated depreciation of ~~which the Company has a 20% ownership interest, approximated 85% during the nine months ended September 30, 2017 and 2016, respectively.~~

~~During the nine months ended September 30, 2017, the Company’s generating plants provided 65% of its retail load requirement compared with~~ ~~69%~~ ~~in the nine months ended September 30, 2016. The decrease in the proportion of power generated~~Colstrip to ~~meet the Company’s retail load requirement was largely due to the combination of decreased~~

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production from the Company’s wind facilities due to unfavorable weather conditions and a reduction in energy provided from the Company’s thermal generation facilities due to outages and economic displacement. The decrease was partially offset by favorable hydro generation, during the first nine months of 2017. Favorable hydro conditions within the region had the effect of reducing energy prices in the wholesale power market which allowed the Company to economically displace a greater portion of its thermal generation to meet its retail load requirement.

Energy expected to be received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually in the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the nine months ended September 30, 2017, energy received from these hydro resources increased by 13% compared to the nine months ended September 30, 2016. Energy received from these hydro resources exceeded projected levels included in PGE’s AUT by 10% and fell below projected levels by 2% for the nine months ended September 30, 2017 and 2016, respectively, and provided 19% and 18% of the Company’s retail load requirement for the nine months ended September 30, 2017 and 2016, respectively. Energy from hydro resources is expected to exceed levels projected in the AUT for 2017.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. For the nine months ended September 30, 2017, energy received from these wind generating resources decreased 18% compared to the nine months ended September 30, 2016, resulting in the Company incurring higher replacement costs, as well as generating fewer Production Tax Credits (PTCs) than what was estimated in customer prices. Energy received from these wind generating resources fell short of that projected in PGE’s AUT by20% for the nine months ended September 30, 2017 and 6% for the nine months ended September 30, 2016, and provided 9% and 12% of the Company’s retail load requirement during the nine months ended September 30, 2017 and 2016, respectively. Energy from wind resources is expected to be below projected levels included in the AUT for 2017.

Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricityDecember 31, 2025. In order to meet PGE’s ~~retail load~~regulatory and legislative requirements, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s condensed consolidated statements of income) and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income. Effective January 1, 2017, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year with actual variances subject to the PCAM. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $30 million above to $15 million below baseline NVPC, the PCAM provides for 90% of the variance beyond the deadband to be collected from, or refunded to, customers, respectively, subject to a regulated earnings test.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in the Company’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense.

For the nine months ended September 30, 2017, actual NVPC was $14 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2017 is currently estimated to be above the baseline NVPC, but within the deadband range. Accordingly, no estimated collection from, or refund to, customers is expected under the PCAM for 2017.

~~For the nine months ended September 30,~~ ~~2016, actual NVPC was~~ ~~$3 million~~ below baseline NVPC. For the year ended December 31, 2016, actual NVPC was $10 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to PCAM for 2016.

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PGE has contractual access to natural gas storage in Mist, Oregon from which it can draw in the event that natural gas supplies are interrupted or if economic factors require its use. The storage facility is owned and operated by a local natural gas company, NW Natural, and may be utilized to provide fuel to PGE’s Port Westward Unit 1 and Beaver natural gas-fired generating plants and the Port Westward Unit 2 natural gas-fired flexible capacity generating plant. PGE has entered into a long-term agreement with this gas company to expand the current storage facilities, including the construction of a new reservoir, compressor station, and 13-miles of pipeline, which will collectively be designed to provide no-notice storage services to these PGE generating plants. NW Natural estimates construction will be completed during the winter of 2018-2019, at a cost of approximately $128 million. Due to the level of PGE’s involvement during the construction period, the Company ~~is deemed~~continues to beevaluate the ~~owner~~possibility of the assets for accounting purposes during the construction period. As a result, PGE has recorded $94 million to construction work-in-progress (CWIP) and a corresponding liability for the same amount to Other noncurrent liabilitiesexiting ownership in the condensed consolidated balance sheets as of September 30, 2017. Upon completion of the facility, PGE will assess whether the assets and liabilities qualify as a successful sale-leaseback transaction in which the asset and liability are removed and accounted for as either a capital or operating lease.

~~Carty~~—Pursuant to the final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, the Company was authorized to include in customer prices the capital costs for Carty of up to $514 million, as well as Carty’s operating costs, effective August 1, 2016, following the placement of the plant into service on July 29, 2016. As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. This higher cost of service is primarily due to depreciation and amortization on the incremental capital cost, interest expense, and legal expense, all of which totaled $12 million for the nine months ended September 30, 2017 and is estimated to be approximately $14 million for the full year 2017.

On July 29, 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent GRC proceeding. The Company has requested the OPUC delay its review of this deferral request until the Company’s claims against the Sureties have been resolved. Until such time, the effects of this higher cost of service will be recognized in the Company’s results of operations. Any amounts approved by the OPUC for recovery under the deferral filing will be recognized in earnings in the period of such approval.

~~For additional details regarding various legal and regulatory proceedings related to Carty, see~~Colstrip. See Note ~~7, Contingencies, in the Notes to the Condensed Consolidated Financial Statements.~~

~~Legal, Regulatory, and Environmental Matters~~—PGE is a party to certain proceedings, the ultimate outcome of which may have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, the following matters:

~~An investigation of environmental matters regarding Portland Harbor;~~

~~Claims pertaining to the termination of the Construction Agreement for Carty and recovery of incremental costs.~~

~~For additional information regarding the above and other matters, see Note 7,~~8, Contingencies, in the Notes to Condensed Consolidated Financial ~~Statements.~~Statements in Item 1.—“Financial Statements” for information regarding legal proceedings related to Colstrip.

~~Oregon Clean Electricity and Coal Transition Plan—The State of Oregon passed Senate Bill 1547, effective~~Any reduction in ~~March 2016, a law referred~~generation from Colstrip has the potential to as the Oregon Clean Electricity and Coal Transition Plan (OCEP). The legislation has impacted PGE in several ways, including preventing the Company from including the costs and benefits associated with coal-fired generation in Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for the Company’s output fromprovide additional capacity availability on the Colstrip ~~facility). As a result,~~transmission facilities, which stretch from eastern Montana to near the western end of that state to serve markets in ~~October 2016,~~ the ~~Company filed a tariff request,~~Pacific Northwest and ~~the OPUC approved the request, to incorporate~~neighboring states. PGE has an approximate 15% ownership interest in, ~~customer prices,~~and capacity on, ~~January 1, 2017, the approximate~~

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~~$6 million annual effect of accelerating recovery of~~ the Colstrip ~~facility from 2042 to 2030, as required under the legislation.~~transmission facilities. See “Investing in a Clean Energy Future” in this Overview for information regarding development in eastern Montana.

~~Future effects under the new law include:~~Other provisions of SB 1547:

~~an increase in~~•established RPS thresholds toof 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;

~~a limitation on~~•limited the life of renewable energy ~~certificates~~credits (RECs) generated from facilities that become operational after 2022 to five years, but ~~continued~~continue unlimited lifespan for all existing RECs and ~~allowance~~allow for the generation of additional unlimited RECs for a period of five years for projects ~~on line~~online before December 31, 2022; and

~~an allowance for~~•provided opportunity to pursue recovery of energy storage costs related to renewable energy in ~~its renewable adjustment clause mechanism~~the Company’s Renewable Adjustment Clause (RAC) filings.

PGE believes it is on track to meet the 2025 RPS threshold.

Regulatory Matters

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

General Rate Case—On February 29, 2024, PGE filed with the OPUC a GRC based on a 2025 test year (2025 GRC) that seeks a $225 million increase in the annual revenue requirement related primarily to recovery of costs associated with non-emitting battery projects, an increase in base business costs for upgrades to PGE's transmission and distribution system, and investments in strengthening and safeguarding the grid to meet growing customer demand and bolster reliability. PGE continues to build a modern grid designed to withstand severe weather and allow energy to flow from more resources to improve reliability, resiliency, and capability to deliver safe, reliable, clean electricity to customers. The total increase in annual revenue requirement includes an increase in annual revenue requirement of $37 million as a result of higher net variable power costs expected in 2025, as reflected in the Annual Power Cost Update Tariff (AUT) filed, separately, with the OPUC February 29, 2024 (OPUC Docket UE 436). The NVPC projection will be updated periodically during 2024.

Other key items in the 2025 GRC filing include requests for a Renewable Automatic Adjustment Clause mechanism for standalone energy storage and an investment recovery mechanism.

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The ~~Company has evaluated~~proposed net increase in annual revenue requirement in the ~~potential impacts~~2025 GRC was based upon a:

•capital structure of 50% debt and ~~has incorporated the effects~~50% equity;

•return on equity of 9.75%;

•cost of capital of 7.189%; and

•rate base of $7.5 billion.

Regulatory review of the ~~legislation into its 2016 IRP.~~

~~Clean Power Plan—In August 2015, the U.S. Environmental Protection Agency (EPA) released a final rule, which it calls the “Clean Power Plan” (CPP). Under the final rule, each state would have~~2025 GRC is expected to reduce the carbon intensity of its power sector on a state-wide basis by an amount specified by the EPA. The rule establishes state-specific goals in terms of pounds of carbon dioxide emitted per MWh of energy produced. The rule is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030.

The target amount was determined based on the EPA’s view of the options for each state, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants; and iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy). The final goal would need to be met by 2030 and interim goals for each state would need to be met from 2022 to 2029. Under the rule, states have flexibility in designing programs to meet their emission reduction targets, including the three approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

PGE cannot predict how the states in which the Company’s thermal generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations. The Company continues to monitor the developments around the implementation of the rule and efforts by state regulators to develop state plans. On February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the CPP pending the resolution of legal challenges to the rule.

On March 28, 2017, the President of the United States issued an Executive Order that directed various agencies to review existing regulations that “potentially burden” the development of the nation’s energy resources. Among other items, the Executive Order specifically directs the EPA to take several actions relating to the CPP. The EPA is instructed to review the final CPP and the final new source performance standard rules for new and modified power plants (NSPS) under the Clean Air Act and suspend, revise, or rescind the rules, if appropriate. On October 16, 2017, the EPA published a proposed rule that is now open for comment, in which it outlined the rationale for repealing the CPP.

continue throughout 2024. The Company cannot predict the ~~impact of the stay, the~~ ultimate outcome of the ~~legal challenges, or whether Oregon and Montana will continue~~remaining regulatory process. A final order on the 2025 GRC is targeted to ~~develop implementation plans in light of the Supreme Court stay, the Executive Order, and consequential EPA actions.~~

~~SB 978—The State of Oregon legislature passed a bill in its 2017 session referred to as SB 978, which directs~~be issued by the OPUC by the end of 2024, with new customer prices to ~~investigate~~take effect January 1, 2025.

The 2025 GRC filing (OPUC Docket UE 435) and the 2025 AUT filing, including copies of direct testimony and exhibits, are available on the OPUC website at www.oregon.gov/puc.

Declared states of emergency—In 2021, the OPUC issued an order that approved a pre-authorized deferral of costs associated with declared states of emergency. Qualifying events would include federal or state declared emergencies with impacts on PGE’s service territory. Previously the Company had to file a request for deferred accounting when an event of that nature occurred, and had to seek OPUC approval of such deferred accounting applications to be effective. With this order, PGE would provide ~~a report~~notice of an event that qualifies and would not need to seek OPUC approval to apply deferred accounting treatment for incremental costs related to the ~~legislature by September 15, 2018 on how developing industry trends, technology, and policy drivers~~emergency. The OPUC maintains responsibility to review utility requests to amortize deferred amounts in customer prices, including a review of utility prudence in a future proceeding, among other requirements.

Beginning January 13, 2024, the ~~electricity sector might impact the existing regulatory system and~~

~~Table of Contents~~

~~incentives. PGE is actively working on this initiative, both internally and in conjunction with the OPUC, to provide guidance and support development of the report.~~

~~Recovery of Utility License Fees—In May 2011, the city of Gresham, Oregon (Gresham), which is within PGE’s~~Company’s service territory ~~adopted~~encountered a ~~resolution~~severe winter weather event that included snow, ice, and high winds over several days that caused catastrophic damage to ~~increase utility license fees from 5%~~physical assets and resulted in widespread customer power outages. Along with over a dozen mutual assistance crews, PGE repaired damage and restored power to ~~7%, effective July 1, 2011. The Company believed that these utility license fees met~~over 500,000 customers throughout the definition of privilege taxes within the Oregon statutes and that Gresham’s increase violated the statutory 5% limitation on such taxes. PGE began collecting the incremental 2% tax from customers in Gresham, but filed suit against Gresham in Multnomah County Circuit Court, claiming that such an increase in privilege taxes violated Oregon law. In January, 2012, the Multnomah County Circuit Court ruled in favor of PGE,storm and the ~~Company ceased collecting from Gresham~~days that followed.

As of March 31, 2024, PGE incurred $60 million in incremental costs to repair damage to PGE’s transmission and distribution systems and restore power to customers, ~~the incremental 2% tax. Gresham appealed the Multnomah County Circuit Court decision~~with $48 million of that representing operating expenses associated with transmission and distribution. PGE expects to incur and defer additional costs subsequent to the ~~Oregon Court~~storm related to addressing vegetation and other debris and hazards both in and outside of ~~Appeals, which subsequently ruled in Gresham’s favor.~~

~~PGE appealed~~PGE’s property and right-of-way, however the ~~Court of Appeals’ ruling~~Company does not expect these costs to ~~the Oregon Supreme Court and on August 4, 2016, the Oregon Supreme Court issued its appellate judgment in favor of Gresham.~~be material. As a result of ~~this ruling,~~ the ~~Company was required~~historic winter storm, Oregon’s Governor declared a state of emergency on January 18, 2024, which allows PGE to ~~pay Gresham $0.8 million, which represented~~seek recovery of incremental storm expenses through the ~~amount it had already collected from customers, plus $7 million~~previously filed emergency deferral. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC, under Docket UM 2190, related to the emergency restoration costs for the ~~remaining accrued, but uncollected, amount~~January storm and as of incremental taxes that were not paid to Gresham when due, covering the period from July 1, 2011 through September 1, 2016. PGE recorded a corresponding regulatory asset for the $7 million. On February 24, 2017, the Company made a filing requesting that the OPUC allow recovery of the $7 million from customers in Gresham over a five-year period.

On May 26, 2017, the OPUC Staff recommended against such recovery, stating that the OPUC has no legal authority to allow PGE to retroactively recover, from customers in Gresham, costs arising from the City’s privilege tax increase. PGE disputes the Staff’s position and believes that such amounts are legally eligible for recovery through customer prices. However, the Company cannot predict the outcome of this matter. The OPUC has indicated that it will render a decision by February 1, 2018.

~~Other Regulatory Matters~~—The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the first three quarters of 2017 compared to the first three quarters of 2016, or have affected retail customer prices, as authorized by the OPUC. In some cases, the CompanyMarch 31, 2024 has deferred ~~the related expenses or benefits~~$48 million of these costs as regulatory ~~assets or liabilities, respectively, for later amortization~~assets. For further information, see “January 2024 storm and ~~inclusion~~ damage” in ~~customer prices, pending OPUC review~~the Regulatory Assets and ~~authorization.~~Liabilities section of Note 3, Balance Sheet Components in the Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements.”

Power ~~Costs~~costs—Pursuant to the AUT process, PGE annually files ~~annually~~ an estimate of power costs for the following year. ~~Effective January 1, 2017, customer prices were decreased $56 million annually from 2016 levels to reflect an expected reduction~~As approved by the OPUC, the 2024 AUT included a final increase in power costs ~~under the AUT. As part~~for 2024, and a corresponding increase in annual revenue requirement, of ~~its 2018 GRC, PGE included a projected reduction in power costs of $29~~$216 million ~~that was included in the overall request submitted to the OPUC and expected to be~~from 2023 levels, which were reflected in customer prices effective January 1, ~~2018.~~2024.

Portland Harbor Environmental Remediation Account (PHERA) mechanism—The EPA has listed PGE as one of over one hundred Potentially Responsible Parties (PRPs) related to the remediation of the Portland Harbor Superfund site. As ~~submitted in~~of March 31, 2024, significant uncertainties still remained concerning the ~~September 29, 2017 GRC update,~~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 ~~further reduced the projected power costs that resulted~~will share in a portion of these costs. In

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a Record of Decision (ROD) issued in 2017, the EPA outlined its selected remediation plan for clean-up of the Portland Harbor site, which had an estimated total ~~reduction~~cost of ~~$36 million. Pursuant~~$1.7 billion. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of Portland Harbor. However, the Company may obtain sufficient information, prior to the ~~schedule established in the proceeding, updates~~final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording an estimate, or low end of the ~~forecast will occur through mid-November that~~range. The Company’s liability related to the cost of remediating Portland Harbor could ~~change this estimate.~~

~~Under~~be material to PGE’s financial position. The impact of such costs to the ~~PCAM for 2016, NVPC was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the~~Company’s results of operations is mitigated by the ~~PCAM for 2016 during~~PHERA mechanism. As approved by the ~~latter half~~OPUC, the recovery mechanism allows the Company to defer and recover estimated liabilities and incurred legal and technical analysis expenditures related to the Portland Harbor Superfund Site through a combination of ~~2017 with a decision expected in the fourth quarter 2017.~~

~~As a result of the recently passed OCEP legislation described above, PGE’s 2017 AUT filing included projected PTCs for the 2017 calendar year. Prior~~third-party proceeds, including, but not limited to, this legislative change, PGE included forecasts of PTCs only in General Rate Case proceedings. The inclusion of PTCs in the AUT provides for annual forecast updates for these estimated tax credits, thus reducing the risk of regulatory lag in terms of adjustinginsurance recoveries, and customer prices, as ~~well as providing the Company~~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 ~~opportunity to potentially collect or refund variances from projected PTC’s pursuant~~annual earnings test. PGE’s results of operations may be impacted to the ~~PCAM.~~

~~Table of Contents~~

~~Renewable Resource Costs—Pursuant to the RAC, PGE can recover in customer prices prudently incurred costs of renewable resources that are expected~~extent such expenditures were to be ~~placed~~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 ~~service~~Note 8, Contingencies in the ~~current year. The Company may submit a filing~~Notes to the OPUC by April 1st each year, with prices expected to become effective January 1st of the following year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet includedCondensed Consolidated Financial Statements in ~~customer prices until the January 1st effective date.~~Item 1.—“Financial Statements.”

~~In March 2016, PGE submitted to the OPUC a RAC filing that requested no significant additions or deferrals for 2016. No RAC filing has been submitted in 2017.~~

Decoupling—The decoupling mechanism, ~~which~~previously authorized by the OPUC ~~has authorized~~ through ~~2019, provides~~2022, was intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency, customer-owned generation, and conservation efforts by residential and certain commercial customers. The mechanism ~~provides~~provided for collection from (or refund to) customers if ~~weather adjusted~~weather-adjusted use per customer iswas less (or more) than that projected in the Company’s most recent ~~general rate case.~~GRC.

~~Accordingly, a refund~~In the 2022 GRC, parties reached an agreement that eliminated PGE’s decoupling mechanism upon the effective date of ~~the $5 million recorded during 2014 occurred over a one-year period, which began January 1, 2016. The $9 million refund recorded in 2015~~new customer prices that resulted ~~from variances between actual weather adjusted use per~~in May 2022. Pursuant to the 2022 GRC Order, the OPUC adopted the agreement such that deferrals would not occur after 2022, although amortization of then previously recorded deferrals was to continue as scheduled until collected or refunded in future customer ~~and that projected in the 2015 GRC, is expected to occur over a one-year period, which began January 1, 2017. The Company recorded an estimated collection of $3 million during~~prices. For the year ended December 31, ~~2016, as a result of variances from amounts established~~2022, with OPUC approval, PGE is collecting $5 million in ~~the 2016 GRC. Any collection for the year ended December 31, 2016 is expected to occur~~customer prices over a one-year period that began January 1, 2024.

In the 2024 GRC filing, the Company included a concept proposal that could lead to resuming decoupling, with certain modifications. As stipulated in the 2024 GRC settlement agreement, PGE made a tariff filing on January 26, 2024 that proposes weather-normalized decoupling, which would ~~begin January 1, 2018.~~

sunset after December 31, 2025, for residential and small non-residential customers. The proposal seeks a 3% annual limit on collections or refunds and a balancing account, which would carry forward to subsequent years for refund or recovery, to capture any amounts that exceed the limit. The Company ~~recorded an estimated collection of $9 million during~~subsequently agreed to extend the ~~nine months ended September 30, 2017, which resulted~~requested effective date from ~~projections established in~~April 1, 2024 to May 1, 2024. However, PGE is now requesting to extend the ~~2016 GRC. Collections under~~effective date to July 1, 2024. An OPUC decision on the ~~decoupling mechanism are subject to an annual limitation, which for 2017 would currently stand at $18 million. Any collection from (or refund to) customers for the 2017 year~~proposal is expected ~~to occur over a one-year period, which would begin January 1, 2019.~~at an upcoming public meeting.

~~Storm Restoration Costs~~Renewable recovery framework—~~Beginning in 2011,~~As previously authorized by the OPUC, ~~authorized~~ the ~~Company~~RAC is a primary method available to collect $2.0 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. If approved, stipulations filed with the OPUC in the 2018 GRC would increase the annual collection amount to $2.6 million, annually beginning in 2018.

~~During 2015 and 2016, PGE fully utilized the existing reserve balance as a result of restoration~~recover costs associated with ~~storm damage occurring during those years. As a result~~renewable resources. The RAC allows PGE to recover prudently incurred costs of renewable resources through filings made each year, outside of a ~~series of storm events~~GRC. Under the RAC, during 2023, the Company submitted a filing for Clearwater, which went into service in January 2024. See “Clearwater RAC” in Note 3, Regulatory Assets and Liabilities, in the ~~first half of 2017,~~Notes to Condensed Consolidated Financial Statements in Item 1.—“Financial Statements,” for more information regarding the Company exhausted the $2 million storm collection authorized for 2017. Consequently, PGE is exposed to the incremental costs to-date related to such major storms events, which total $10 million, less the amount to be collected in 2017, as well as any additional major storm damage costs experienced during the remainder of 2017.

~~As a result~~timing of the additional costs incurred, during the first quarter of 2017, PGE filed an application with the OPUC requesting authorization to defer incremental storm restoration costs from the date of the application through the end of 2017, net of the $2 million being collected annually under the existing methodology. Since the application will not likely be reviewed until 2017 is complete,tariff, annual revenue requirement, and all applicable costs are identified, the Company is unable to predict how the OPUC will ultimately rule on this application. The Company is unable to state with any certainty at this time whether these incremental costs are probable of recovery and, accordingly, no deferral has been recorded to-date. In the event it becomes probable that some or all of these costs are recoverable, the Company will record a deferral for such amounts at such time.related deferral.

Operating Activities

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~~Integrated Resource Plan~~—In ~~November 2016, PGE filed an IRP (2016 IRP) with the OPUC. The 2016 IRP addresses acquisition of additional resources~~addition to electricity provided by PGE’s own generation portfolio, to meet ~~RPS~~retail load requirements and ~~replace~~balance energy supply with customer demand, the Company purchases and ~~capacity from Boardman,~~sells electricity in the wholesale market. To fuel its generation portfolio, the Company purchases natural gas in the United States and Canada and sells excess gas back into the wholesale market. PGE also performs portfolio management and wholesale market services for third parties in the region.

The Company participates in the California Independent System Operator's (CAISO) western Energy Imbalance Market (EIM), which will cease coal-fired operations at the end of 2020. Further actions identified through 2021 are expected to offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities. The 2016 IRP also considers the OCEP, which,allows, among other things, ~~increased~~more renewable energy integration into the ~~RPS requirements for 2025 and future years. For further information~~grid by better complementing the variable output of renewable resources. PGE recently announced plans to join the CAISO’s Extended Day-Ahead Market (EDAM) to build on the ~~OCEP, see~~success of the ~~“Legal, Regulatory~~western EIM and ~~Environmental”~~ ~~section in this Overview section of Item 2.~~

~~All portfolios analyzed~~help provide the Company and its customers access to more affordable, reliable and clean energy. Utilities that participate in the ~~2016 IRP pursue:~~EDAM, expected to begin operating in 2026, will bid their anticipated energy demand and generating resources into the market a day ahead of expected usage. The EDAM will then optimize generation resources and the energy needed for all market participants, allowing them to receive the least costly and cleanest energy to meet their energy needs. The EDAM takes advantage of existing technology and systems PGE has deployed and leverages the Company’s transmission system to connect regional resources across a common market, such as hydropower and wind facilities in the Pacific Northwest and solar facilities in California and the desert Southwest.

~~compliance with the RPS through 2050;~~

~~inclusion of cost-effective customer-side options, including energy efficiency, demand response, conservation voltage reduction, and dispatchable standby generation; and~~

~~retention of all existing power plants until 2050, with the exception of Boardman and Colstrip Units 3 & 4.~~

In ~~August 2017,~~its ongoing effort to benefit retail and wholesale customers, in 2023, PGE joined the ~~OPUC acknowledged PGE’s 2016 IRP~~Western Power Pool’s resource adequacy program known as the Western Resource Adequacy Program (WRAP), which could become a binding commitment in 2026 or 2027. The WRAP represents a regional framework to more effectively address resource adequacy, enhance reliability, integrate clean energy, and manage costs through resource diversification and capacity sharing across a wide geographic footprint and broad pool of participants across the West.

PGE 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 and did record a new winter peak load in December 2022. Summer peak deliveries have continued to exceed those of the winter months for several years, generally resulting from air conditioning demand and the ~~following primary action plan items:~~

~~Acknowledge capacity needs of 561 MW, of~~trend toward a warmer overall climate. In August 2023, demand reached a new all-time high, surpassing the previous mark, which ~~240 MW must~~was set in summer 2021. Retail customer price changes and customer usage patterns, which can be ~~dispatchable, in 2021;~~

~~Acquire a total of 135 MWa of cost-effective energy efficiency;~~

~~Acquire at least 77 MW (winter)~~affected by the economy also have an effect on revenues. Wholesale power availability and ~~69 MW (summer) demand response through 2020~~price, hydro and ~~16 MW of dispatchable standby~~wind generation, and fuel costs for thermal plants can also affect income from ~~customers~~operations. PGE has taken measures to help ~~manage peak load conditions~~ensure the availability of supply chain-constrained items that are needed to serve new and ~~other supply contingencies;~~

~~Deploy 1 MWa~~existing customers, such as advance ordering of ~~conservation voltage reduction through 2020;~~

~~Submit one or more energy storage proposals in accordance~~critical materials, pre-securing manufacturing capacity with ~~House Bill 2193, by January 1, 2018,~~strategic partners, and evaluating availability with ~~an initial proposal expected to be filed with the OPUC by mid-November 2017;~~established and

Perform various research and studies related to flexible capacity and curtailment metrics, customer insights, decarbonization, risks associated with Direct Access, treatment of market capacity, accessing resources from Montana, and load forecasting improvements.

PGE is engaged in bilateral negotiations with owners of existing regional resources to fill its capacity need. In August 2017, the Company filed with the OPUC a request for a waiver of the OPUC’s competitive bidding guidelines. In that filing, PGE requests a waiver to procure 350 - 450 MW of capacity to partially satisfy PGE’s 561 MW capacity deficit. PGE expects additional capacity contributions from contracts with Qualifying Facilities as defined by the Public Utility Regulatory Policies Act of 1978, acquisition of energy storage in compliance with House Bill 2193, and an assumed capacity contribution from incremental renewables procured through a request for proposal (RFP). The OPUC is scheduled to make a decision on the waiver request by December 5, 2017 and the Company currently anticipates negotiations to be complete by the end of the first quarter of 2018. Following the outcome of the bilateral negotiations and waiver process, PGE may request approval from the OPUC to issue RFPs for any remaining capacity need.

The OPUC did not acknowledge PGE’s proposed actions for acquiring renewable resources and asked the Company to work with OPUC staff and parties to prepare and submit a revised proposal, which PGE presented at a public meeting on October 10, 2017. In the revised proposal, the Company identified the potential of revising the procurement target for the addition of RPS compliant renewable resources to 100 MWa, which could include unbundled RECs. PGE expects to submit an IRP addendum by the end of 2017 that would seek acknowledgement of a revised renewable action plan, including the issuance of RFPs for renewable resources.

~~Since issuing the IRP,~~ new suppliers. PGE has ~~identified a potential benchmark wind resource that could have a nameplate capacity of up~~also taken measures to ~~approximately 300 MW, that would meet~~help mitigate cost increases through long-term agreements, supplier engagement, and expanding the ~~need for the renewable resources, and which would qualify for the production tax credit. The Company continues to explore this option. The submission of this resource into an~~supply base.

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~~RFP for renewable resources as a benchmark bid is subject to additional due diligence~~Customers and ~~negotiation along with execution of definitive agreements. If agreements are reached, the potential benchmark resource would be considered in the RFP along with other renewable resource offerings.~~

~~The RFP process will include oversight by an independent evaluator and review by the OPUC.~~

~~Critical Accounting Policies~~

~~PGE’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended~~ ~~December 31, 2016, filed with the SEC on~~ ~~February 17, 2017~~.

~~Results of Operations~~

Demand—The following ~~table contains condensed consolidated statements of income information for the periods presented (dollars in millions):~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues, net $ 515
100 % $ 484
100 % $ 1,494
100 % $ 1,399
100 %
Purchased power and fuel 184
36
180
37
443
30
455
33
Gross margin 331
64
304
63
1,051
70
944
67
Other operating expenses:
Generation, transmission and distribution 73
14
69
14
235
16
199
14
Administrative and other 64
12
63
13
197
13
185
13
Depreciation and amortization 87
17
79
17
257
17
244
18
Taxes other than income taxes 30
6
29
6
94
6
89
6
Total other operating expenses 254
49
240
50
783
52
717
51
Income from operations 77
15
64
13
268
18
227
16
Interest expense* 30
6
28
6
90
6
82
6
Other income:
Allowance for equity funds used during construction 4
1
4
1
9
1
19
1
Miscellaneous income, net 2
1
—
—
4
—
—
—
Other income, net 6
2
4
1
13
1
19
1
Income before income tax expense 53
11
40
8
191
13
164
11
Income tax expense 13
3
6
1
46
3
32
2
Net income $ 40
8 % $ 34
7 % $ 145
10 % $ 132
9 %

* Net of an allowance for borrowed funds used during construction of $1 million for the three months ended September 30, 2017 and 2016, and $4 million and $10 million for the nine months ended September 30, 2017 and 2016.

~~Net income~~ was $40 million, or $0.44 per diluted share, for the three months ended September 30, 2017 compared with $34 million, or $0.38 per diluted share, for the three months ended September 30, 2016. The increase in Net income reflects higher usage per customer across all customer classes, along with the effect of warmer weather in 2017 compared to the same period of 2016. Depreciation and amortization expense increased due to capital additions including Carty, a portion of which is offset in higher revenues.

~~Net income~~ was $145 million, or $1.62 per diluted share, for the nine months ended September 30, 2017, compared with $132 million, or $1.49 per diluted share, for the nine months ended September 30, 2016. Temperature contrasts contributed to highertables present total energy ~~demand in the first three quarters of 2017 than 2016 and helped improve Gross margin. While total~~ deliveries and customer growth remains favorable, weather-adjusted usage per residential customer continues a pattern of long-term decline. As a result, the Company recorded a $6 million increase in the estimated collection under the Decoupling mechanism in the first three quarters of 2017 compared with the first three quarters

~~Table of Contents~~

of 2016. Net income was aided by reduced NVPC as the average variable power cost per MWh declined 5%. NVPC was $14 million above baseline NVPC for the first three quarters of 2017, compared with $3 million below the baseline for the first three quarters of 2016. Allowance for equity funds used during construction decreased by $10 million in the first three quarters of 2017 in comparison with the first three quarters of 2016 due to lower average CWIP balances. Higher operating expenses, including additional depreciation expense, contributed to partially offset the higher net income. Lower AFDC in 2017 resulted from the completion of Carty in July 2016, and, although recovery in customer prices began in August 2016, some earnings drag continues as costs exceeded those authorized by the OPUC. Expenses related to Carty (primarily incremental depreciation, interest, and legal costs) continue to reduce earnings.

~~Three Months Ended September 30, 2017 Compared with the Three Months Ended September 30, 2016~~

~~Revenues, energy deliveries (presented in MWh),~~ and the average number of retail customers ~~consist of the following~~by customer type for the periods ~~presented:~~

indicated:


										Three Months Ended March 31,
										Three Months Ended March 31,
										Three Months Ended March 31,
											2024
											2024
											2024

	Three Months Ended September 30,
	2017					2016
Revenues^* (dollars in millions):

Energy deliveries (MWhs in thousands):

Energy deliveries (MWhs in thousands):

Energy deliveries (MWhs in thousands):
Retail:
Retail:
Retail:
Residential	$	224		43	%	$	203	42	%
Residential
Residential
Commercial
Commercial
Commercial	178			35		170		35
Industrial	55			11		54		11
Industrial
Industrial
Subtotal	457			89		427		88
Other retail revenues, net	(2		)	(1	)	1		—
Total retail revenues	455			88		428		88
Wholesale revenues	50			10		48		10
Other operating revenues	10			2		8		2
Total revenues	$	515		100	%	$	484	100	%
Energy deliveries (MWh in thousands):
Retail:
Residential	1,817			29	%	1,618		27	%
Subtotal
Subtotal
Direct access:
Direct access:
Direct access:
Commercial
Commercial
Commercial	1,851			30		1,751		30
Industrial	752			12		754		13
Subtotal	4,420			71		4,123		70
Direct access:
Commercial	169			3		141		2
Industrial
Industrial	366			6		301		5
Subtotal	535			9		442		7
Total retail energy deliveries	4,955			80		4,565		77
Wholesale energy deliveries	1,224			20		1,360		23
Total energy deliveries	6,179			100	%	5,925		100	%
Average number of retail customers:
Residential	763,553			88	%	753,345		87	%
Commercial	108,705			12		107,844		13
Industrial	200			—		204		—
Direct access	588			—		373		—
Subtotal
Subtotal
Total retail
Total retail
Total retail
Wholesale
Wholesale
Wholesale
Total	873,046			100	%	861,766		100	%
Total
Total


Oregon		93-0256820

~~Oregon~~	~~93-0256820~~
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)


(Title of class)	(Trading Symbol)	(Name of exchange on which registered)
Common Stock, no par value	POR	New York Stock Exchange



Large accelerated filer ~~[x]~~	☒		Accelerated filer ~~[ ]~~		☐
Non-accelerated filer ~~[ ]~~		~~(Do not check if a smaller reporting company)~~
☐	Smaller reporting company ~~[ ]~~		☐
				Emerging growth company ~~[ ]~~		☐



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Income and Comprehensive Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2931

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5257

Item 4.	Controls and Procedures	5258

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	5358

Item 1A.	Risk Factors	5558



Item 6.5.	~~Exhibits~~Other Information	5561

Item 6.	Exhibits	60

SIGNATURE		5561


	March 31, 2024		December 31, 2023
ASSETS
Current assets:
Cash and cash equivalents	$	176	$	5
Accounts receivable, net	412		414

Inventories	114		113

Regulatory assets—current	177		221
Other current assets	203		182
Total current assets	1,082		935
Electric utility plant, net	9,663		9,546
Regulatory assets—noncurrent	606		492
Nuclear decommissioning trust	30		31
Non-qualified benefit plan trust	36		35
Other noncurrent assets	171		169
Total assets	$	11,588	$	11,208

See accompanying notes to condensed consolidated financial statements.


☒
~~[X]~~	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐
~~[ ]~~	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Abbreviation or Acronym	Definition
~~AFDC~~AFUDC		Allowance for funds used during construction
AUT		Annual Power Cost Update Tariff
~~Boardman~~		~~Boardman coal-fired generating plant~~
~~Carty~~		~~Carty natural gas-fired generating plant~~

Colstrip		Colstrip Units 3 and 4 coal-fired generating plant
~~CWIP~~
EFSA		~~Construction work-in-progress~~Equity Forward Sale Agreement
EPA		United States Environmental Protection Agency

FERC		Federal Energy Regulatory Commission
~~FMBs~~FMB		First Mortgage ~~Bonds~~Bond
GAAP		Accounting principles generally accepted in the United States of America
GRC		General Rate Case
IRP		Integrated Resource Plan
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt ~~hours~~hour
~~NVPC~~Nasdaq		National Association of Securities Dealers Automated Quotations
NVPC		Net Variable Power Costs
~~OCEP~~NYSE		~~Oregon Clean Electricity and Coal Transition Plan~~New York Stock Exchange

OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
~~RPS~~ROE		Regulated return on equity


RPS		Renewable Portfolio Standard
S&P		S&P Global Ratings
SEC		United States Securities and Exchange Commission
~~Trojan~~		~~Trojan nuclear power plant~~



	September 30, 2017		December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	89	$	6
Accounts receivable, net	151		155
Unbilled revenues	71		107
Inventories	70		82
Regulatory assets—current	42		36
Other current assets	43		77
Total current assets	466		463
Electric utility plant, net	6,638		6,434
Regulatory assets—noncurrent	526		498
Nuclear decommissioning trust	41		41
Non-qualified benefit plan trust	37		34
Other noncurrent assets	51		57
Total assets	$	7,759	$	7,527

See accompanying notes to condensed consolidated financial statements.


	March 31, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	289	$	347
Liabilities from price risk management activities—current	137		164
Short-term debt	—		146
Current portion of long-term debt	80		80

Current portion of finance lease obligation	23		20
Accrued expenses and other current liabilities	356		355
Total current liabilities	885		1,112
Long-term debt, net of current portion	4,353		3,905
Regulatory liabilities—noncurrent	1,406		1,398
Deferred income taxes	534		488
Unfunded status of pension and postretirement plans	160		172
Liabilities from price risk management activities—noncurrent	56		75
Asset retirement obligations	273		272
Non-qualified benefit plan liabilities	78		79
Finance lease obligations, net of current portion	285		289
Other noncurrent liabilities	99		99
Total liabilities	8,129		7,889
Commitments and contingencies (see notes)
Shareholders’ Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2024 and December 31, 2023	—		—
Common stock, no par value, 160,000,000 shares authorized; 103,023,507 and 101,159,609 shares issued and outstanding as of March 31, 2024 and December 31, 2023, respectively	1,828		1,750
Accumulated other comprehensive loss	(4)		(5)
Retained earnings	1,635		1,574


Total shareholders’ equity	3,459		3,319
Total liabilities and shareholders’ equity	$	11,588	$	11,208

See accompanying notes to condensed consolidated financial statements.



	September 30, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	100		$	129
Liabilities from price risk management activities—current	43			44
Current portion of long-term debt	100			150
Accrued expenses and other current liabilities	248			254
Total current liabilities	491			577
Long-term debt, net of current portion	2,277			2,200
Regulatory liabilities—noncurrent	1,002			958
Deferred income taxes	701			669
Unfunded status of pension and postretirement plans	288			281
Liabilities from price risk management activities—noncurrent	150			125
Asset retirement obligations	166			161
Non-qualified benefit plan liabilities	105			105
Other noncurrent liabilities	177			107
Total liabilities	5,357			5,183
Commitments and contingencies (see notes)
Equity:
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2017 and December 31, 2016	—			—
Common stock, no par value, 160,000,000 shares authorized; 89,091,955 and 88,946,704 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	1,204			1,201
Accumulated other comprehensive loss	(7		)	(7		)
Retained earnings	1,205			1,150
Total equity	2,402			2,344
Total liabilities and equity	$	7,759		$	7,527

See accompanying notes to condensed consolidated financial statements.



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities:
Net income	$	145		$	132
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	257			244
Deferred income taxes	35			18
Pension and other postretirement benefits	19			21
Allowance for equity funds used during construction	(9		)	(19		)
Decoupling mechanism deferrals, net of amortization	(15		)	(4		)
Other non-cash income and expenses, net	18			12
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	40			53
Decrease in inventories	12			1
Decrease in margin deposits, net	4			25
Increase in accounts payable and accrued liabilities	14			31
Other working capital items, net	20			12
Other, net	(21		)	(29		)
Net cash provided by operating activities	519			497
Cash flows from investing activities:
Capital expenditures	(369		)	(454		)
Sales of Nuclear decommissioning trust securities	14			17
Purchases of Nuclear decommissioning trust securities	(12		)	(16		)
Other, net	(2		)	(1		)
Net cash used in investing activities	(369		)	(454		)

See accompanying notes to condensed consolidated financial statements.


	Three Months Ended March 31,
	2024
Balance as of beginning of period	$	9
Increase in provision	3
Amounts written off	(3)
Recoveries	2
Balance as of end of period	$	11


	March 31, 2024		December 31, 2023
Prepaid expenses	$	109	$	68

Assets from price risk management activities	29		22
Margin deposits	65		92


Other current assets	$	203	$	182



	September 30, 2017		December 31, 2016
Prepaid expenses	$	27	$	48
Assets from price risk management activities	4		18
Margin deposits	4		8
Other	8		3
Other current assets	$	43	$	77


	March 31, 2024		December 31, 2023
Electric utility plant in-service	$	13,881	$	13,329
Construction work-in-progress	628		974
Total cost	14,509		14,303
Less: accumulated depreciation and amortization	(4,846)		(4,757)
Electric utility plant, net	$	9,663	$	9,546



	September 30, 2017			December 31, 2016
Electric utility plant	$	9,766		$	9,534
Construction work-in-progress	386			213
Total cost	10,152			9,747
Less: accumulated depreciation and amortization	(3,514		)	(3,313		)
Electric utility plant, net	$	6,638		$	6,434


	March 31, 2024					December 31, 2023
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	108		$	48	$	143		$	63
Reliability contingency events	—			75		—			—
Pension and other postretirement plans	—			104		—			104


Trojan decommissioning activities	—			141		—			139
February 2021 ice storm and damage	12			53		12			55
January 2024 storm and damage	—			48		—			—

2020 Labor Day wildfire	5			22		5			23

Wildfire mitigation	19			13		19			10
Other	33			102		42			98
Total regulatory assets	$	177		$	606	$	221		$	492
Regulatory liabilities:
Asset retirement removal costs	$	—		$	1,178	$	—		$	1,173
Deferred income taxes	—			171		—			177



Clearwater RAC	—			10		—			—
Other	50			47		48			48
Total regulatory liabilities	$	50	*	$	1,406	$	48	*	$	1,398



	As of September 30, 2017
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	3	$	8	$	—	$	—	$	11
Corporate credit	—		7		—		—		7
Money market funds measured at NAV ⁽²⁾	—		—		—		23		23
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	2		—		—		—		2
Equity securities—domestic	6		—		—		—		6
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV ⁽²⁾	—		—		—		—		—
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		3		—		—		3
Natural gas	—		1		—		—		1
	$	12	$	19	$	—	$	23	$	54
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	3	$	140	$	—	$	143
Natural gas	—		37		13		—		50
	$	—	$	40	$	153	$	—	$	193



	As of December 31, 2016
	Level 1		Level 2		Level 3		Other ⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	2	$	10	$	—	$	—	$	12
Corporate credit	—		8		—		—		8
Money market funds measured at NAV ⁽²⁾	—		—		—		21		21
Non-qualified benefit plan trust: ⁽³⁾
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4
Debt securities—domestic government	1		—		—		—		1
Collective trust—domestic equity measured at NAV ⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		6		1		—		7
Natural gas	—		15		1		—		16
	$	8	$	39	$	2	$	23	$	72
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	6	$	112	$	—	$	118
Natural gas	—		42		9		—		51
	$	—	$	48	$	121	$	—	$	169



	2017		2018		2019		2020		2021		Thereafter		Total
Commodity contracts:
Electricity	$	—	$	9	$	8	$	8	$	8	$	107	$	140
Natural gas	14		22		9		4		—		—		49
Net unrealized loss	$	14	$	31	$	17	$	12	$	8	$	107	$	189




As Filed February 28, 2017				$	100
Load and Power Cost Updates				(28		)
Depreciation Study Updates				(8		)
Base Business Revenue Requirement Updates:
Lower return on equity	$	(10	)
Lower labor costs	(9		)
Adjustment to depreciation expense	(8		)
Lower level of plant in service	(5		)
Other reductions to rate base	(4		)
Other various modifications	(8		)
Subtotal				(44		)
As Stipulated				$	20


	Heating Degree-days
	2024		2023		Avg.

January	759		667		704
February	539		658		606
March	457		602		528









Year-to-date	1,755		1,927		1,838
(Decrease) increase from the 15-year average	(5)	%	5	%



	Heating Degree-days			Cooling Degree-days
	2017	2016	Avg.	2017	2016	Avg.
July	1	3	9	164	140	163
August	1	3	8	275	224	168
September	76	72	61	132	30	68
Totals for the quarter	78	78	78	571	394	399


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

	2024		2023			2024		2023			2024		2023
Generation:
Thermal:
Natural gas	89	%	91	%		110	%	102	%		40	%	43	%
Coal (3)	85		94			93		108			7		9
Wind (4)	92		88			84		101			8		7
Hydro	96		97			97		69			5		4


	Three Months Ended March 31,		% Increase (Decrease)
		2024			2023
Total revenues			$	929		$	748	24	%
Operating expenses:
Purchased power and fuel			405			304		33
Generation, transmission and distribution			99			93		6
Administrative and other			95			80		19
Depreciation and amortization			121			111		9
Taxes other than income taxes			47			43		9
Total operating expenses			767			631		22
Income from operations			162			117		38
Interest expense, net*			51			44		16
Other income:
Allowance for equity funds used during construction			5			3		67
Miscellaneous income, net			6			12		(50)
Other income, net			11			15		(27)
Income before income tax expense			122			88		39
Income tax expense			13			14		(7)
Net income			109			74		47
Other comprehensive income			1			—		—
Net income and Comprehensive income			$	110		$	74	49	%


	Three Months Ended
March 31, 2023	$	651
Change in prices as a result of the AUT, approved by the OPUC (partially offset in Purchased power and fuel)	54
Average price of energy deliveries due primarily to customer price increases	48
Recovery of deferrals for 2020 Wildfire, 2021 ice storm, and COVID-19	5
Change in Decoupling amortization	(2)
Retail energy deliveries driven by changes in customer load	(4)
Clearwater RAC deferral	(10)
Combination of various supplemental tariffs and adjustments	(2)


March 31, 2024	$	740
Change in Total retail revenues	$	89


	Three Months Ended
March 31, 2023	$	304
Average variable power cost ~~increased to $30.99~~ per MWh	125
Total system load	51
2024 RCE deferral	(75)
March 31, 2024	405
Change in Purchased power and fuel	$	101

Average variable power cost per MWh:
March 31, 2023	$	44.25
March 31, 2024	$	62.58

Total system load (MWhs in thousands):
March 31, 2023	6,784
March 31, 2024	7,610


	Actual Runoff as a Percent of Normal*
	Runoff as a Percent of Normal*								Runoff as a Percent of Normal*
Location	2017		2016		Location	2024 Forecast		2023 Actual
Columbia River at The Dalles, Oregon	98	%	89	%	Columbia River at The Dalles, Oregon	81	%	83	%
Mid-Columbia River at Grand Coulee, Washington	98		91
Clackamas River at Estacada, Oregon	97		71
Deschutes River at Moody, Oregon	98		91


	Three Months Ended
March 31, 2023	$	216
Purchased power and fuel expense	176
Wholesale revenues	(88)
2024 RCE deferral	(75)
March 31, 2024	$	229
Change in NVPC	$	13


	Three Months Ended
March 31, 2023	$	93
Generating facility expenses driven by increased major maintenance activities	5
Vegetation management, inspection, wildfire mitigation, and distribution maintenance expenses	4

Service restoration and storm response costs	2
Miscellaneous expenses	(5)
March 31, 2024	$	99
Change in Generation, transmission and distribution	$	6


	Three Months Ended
March 31, 2023	$	80
Amortization of COVID-19 bad debt expense deferral	4
Professional services	3
Employee compensation and benefits	2
Miscellaneous expenses	6
March 31, 2024	$	95
Change in Administrative and other	$	15


~~(1)~~	~~Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connections.~~


~~(2)~~	~~As of December 31, 2016, total capital expenditures for the Customer information project was $65 million, excluding AFDC.~~


~~(3)~~	~~Includes preliminary engineering and removal costs, which are included in other net operating activities in the condensed consolidated statements of cash flows.~~