10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2022

OR

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

For the Transition period from ________ to ________

Commission File Number Exact name of registrant as specified in its charter, state of incorporation,
address of principal executive offices, telephone number I.R.S.
Employer
Identification
Number

1-16305 PUGET ENERGY, INC. A Washington Corporation 355 110th Ave NE Bellevue, Washington 98004 (425) 454-6363 91-1969407

1-4393 PUGET SOUND ENERGY, INC. A Washington Corporation 355 110th Ave NE Bellevue, Washington 98004 (425) 454-6363 91-0374630

Securities Registered pursuant to Section 12(b) of the Securities Exchange Act of 1934

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Puget Energy, Inc. Yes /X/ No /  / Puget Sound Energy, Inc. Yes /X/ No /  /

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Puget Energy, Inc. Yes /X/ No /  / Puget Sound Energy, Inc. Yes /X/ No /  /

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer", "accelerated filer," a smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Puget Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated Filer	/X/	Smaller reporting company	/  /	Emerging growth company	/  /
Puget Sound Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated Filer	/X/	Smaller reporting company	/  /	Emerging growth company	/  /

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Puget Energy, Inc. Yes /  / No /X/ Puget Sound Energy, Inc. Yes /  / No /X/

All of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.  All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.

Table of Contents

		Page
Definitions		3
Filing Format		4
Forward-Looking Statements		4
Part I.	Financial Information	5
Item 1.	Financial Statements	5
	Puget Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2022 and 2021	5
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2022 and 2021	6
	Consolidated Balance Sheets – March 31, 2022 and December 31, 2021	7
	Consolidated Statements of Common Shareholder's Equity - March 31, 2022, and December 31, 2021	8
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2022 and 2021	9
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2022 and 2021	12
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2022 and 2021	11
	Consolidated Balance Sheets – March 31, 2022 and December 31, 2021	12
	Consolidated Statements of Common Shareholder's Equity - March 31, 2022, and December 31, 2021	14
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2022 and 2021	15
	Notes
	Combined Notes to Consolidated Financial Statements	16
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	60
Item 4.	Controls and Procedures	61
Part II.	Other Information	62
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 6.	Exhibits	62
Exhibit Index		63
Signatures		64

2

DEFINITIONS

ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
FASB	Financial Accounting Standards Board
GAAP	U.S. Generally Accepted Accounting Principles
GRC	General Rate Case
ISDA	International Swaps and Derivatives Association
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
MMBtu	One Million British Thermal Units
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NPNS	Normal Purchase Normal Sale
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PTC	Production Tax Credit
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Holdings	Puget Holdings LLC
Puget LNG	Puget LNG, LLC
SERP	Supplemental Executive Retirement Plan
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.

3

FILING FORMAT

This report on Form 10-Q is a Quarterly Report filed separately by two registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE).  Any references in this report to “the Company” are to Puget Energy and PSE collectively.

FORWARD-LOOKING STATEMENTS

Puget Energy and PSE include the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE.  This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance.  Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.

Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed.  There can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.  

In addition to other factors and matters discussed elsewhere in this report, some important risks that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and those discussed in the forward-looking statements include:

● Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;

● Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by-products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

● Changes in tax law, related regulations or differing interpretation, or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;

● Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;

● Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires, extreme weather conditions, landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;

● The impact of widespread health developments, including the global Coronavirus Disease 2019 (COVID-19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, government stay at home orders, restrictions on travel, commercial, social and other activities, and the impact of vaccination mandates on employee and vendor staffing levels) could materially and adversely affect, among other things, electric and natural gas demand, customers’ ability to pay, supply chains, availability of skilled work-force, contract counterparties, liquidity and financial markets;

● Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;

● Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;

● Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;

● The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations or the decision of companies in the Western Interconnection to join such markets) or other related federal initiatives;

● PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;

● Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;

● The ability to restart generation following a regional transmission disruption;

● The ability of a natural gas or electric plant to operate as intended;

● Changes in climate, weather conditions, or sustained extreme weather events in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;

● Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;

● Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;

● Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;

● The ability to renew contracts for electric and natural gas supply and the price of renewal;

● Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;

● General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;

● The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;

● The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;

● Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;

● Capital market conditions, including changes in the availability of capital and interest rate fluctuations;

● Employee workforce factors including strikes; work stoppages; absences due to pandemics, accidents, natural disasters or other significant, unforeseeable events; availability of qualified employees or the loss of a key executive;

● The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;

● Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally;

● Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder; and

● Recent laws proposed or passed by various municipalities in PSE's service territory, including Seattle, seek to reduce or eliminate the use of natural gas in various contexts, such as for space, cooking, and water heating in new commercial and multifamily buildings. Such laws may impact operations due to costs and delays from incremental permitting and other requirements that are outside PSE's control.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company 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, nor can it 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.  For further information, see Item 1A, “Risk Factors” in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Operating revenue:
Electric	$	756,377	$	758,592
Natural gas	426,348		392,906
Other	10,712		8,588
Total operating revenue	1,193,437		1,160,086
Operating expenses:
Energy costs:
Purchased electricity	238,203		205,410
Electric generation fuel	60,644		60,418
Residential exchange	(23,070)		(25,802)
Purchased natural gas	177,333		155,015
Unrealized (gain) loss on derivative instruments, net	(131,921)		(23,002)
Utility operations and maintenance	170,300		160,540
Non-utility expense and other	15,419		9,906
Depreciation & amortization	164,576		208,431
Conservation amortization	30,141		34,060
Taxes other than income taxes	121,377		110,310
Total operating expenses	823,002		895,286
Operating income (loss)	370,435		264,800
Other income (expense):
Other income	13,164		13,630
Other expense	(3,154)		(1,510)
Interest charges:
AFUDC	4,129		3,586
Interest expense	(86,468)		(89,360)
Income (loss) before income taxes	298,106		191,146
Income tax (benefit) expense	19,811		2,153
Net income (loss)	$	278,295	$	188,993

The accompanying notes are an integral part of the financial statements.

5

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Net income (loss)	$	278,295	$	188,993
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $487 and $634, respectively	1,831		2,385
Other comprehensive income (loss)	1,831		2,385
Comprehensive income (loss)	$	280,126	$	191,378

The accompanying notes are an integral part of the financial statements.

6

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	March 31, 2022		December 31, 2021
Utility plant (at original cost, including construction work in progress of $696,617 and $870,204 respectively):
Electric plant	$	9,843,756	$	9,729,643
Natural gas plant	4,553,903		4,498,198
Common plant	1,120,192		1,155,567
Less: Accumulated depreciation and amortization	(4,081,891)		(4,031,458)
Net utility plant	11,435,960		11,351,950
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	326,229		324,897
Total other property and investments	1,982,742		1,981,410
Current assets:
Cash and cash equivalents	603,757		56,946
Restricted cash	30,525		46,204
Accounts receivable, net of allowance for doubtful accounts of $41,233 and $34,958, respectively	419,355		398,895
Unbilled revenue	215,299		271,606
Materials and supplies, at average cost	120,364		113,287
Fuel and natural gas inventory, at average cost	47,360		59,393
Unrealized gain on derivative instruments	293,884		128,210
Prepaid expense and other	50,906		46,293
Power contract acquisition adjustment gain	16,303		17,274
Total current assets	1,797,753		1,138,108
Other long-term and regulatory assets:
Power cost adjustment mechanism	67,808		79,546
Purchased gas adjustment receivable	44,020		57,935
Regulatory assets related to power contracts	9,362		9,689
Other regulatory assets	809,414		815,058
Unrealized gain on derivative instruments	36,690		26,197
Power contract acquisition adjustment gain	59,332		63,660
Operating lease right-of-use asset	182,077		184,957
Other	165,440		163,374
Total other long-term and regulatory assets	1,374,143		1,400,416
Total assets	$	16,590,598	$	15,871,884

The accompanying notes are an integral part of the financial statements.

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	March 31, 2022		December 31, 2021
Capitalization
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—	$	—
Additional paid-in capital	3,523,532		3,523,532
Retained earnings	1,344,572		1,067,216
Accumulated other comprehensive income (loss), net of tax	(25,601)		(27,432)
Total common shareholder’s equity	4,842,503		4,563,316
Long-term debt:
First mortgage bonds and senior notes	4,662,000		4,662,000
Pollution control bonds	161,860		161,860
Long-term debt	2,034,300		1,583,300
Debt discount issuance costs and other	(203,217)		(203,394)
Total long-term debt	6,654,943		6,203,766
Total capitalization	11,497,446		10,767,082
Current liabilities:
Accounts payable	376,793		444,384
Short-term debt	69,750		140,000
Current maturities of long-term debt	450,000		450,000
Accrued expenses:
Taxes	169,124		127,398
Salaries and wages	43,489		47,936
Interest	81,556		67,807
Unrealized loss on derivative instruments	40,237		63,309
Power contract acquisition adjustment loss	1,741		1,785
Operating lease liabilities	20,624		20,398
Other	87,814		62,406
Total current liabilities	1,341,128		1,425,423
Other long-term and regulatory liabilities:
Deferred income taxes	923,026		912,484
Unrealized loss on derivative instruments	22,373		40,965
Regulatory liabilities	930,374		844,184
Regulatory liability for deferred income taxes	852,280		865,976
Regulatory liabilities related to power contracts	75,635		80,934
Power contract acquisition adjustment loss	7,621		7,904
Operating lease liabilities	168,637		172,510
Finance lease liabilities	104,539		105,303
Other deferred credits	667,539		649,119
Total long-term and regulatory liabilities	3,752,024		3,679,379
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	16,590,598	$	15,871,884

The accompanying notes are an integral part of the financial statements.

7

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

(Unaudited)

	Common Stock			Additional Paid-in Capital				Accumulated Other Comprehensive Income (Loss)
	Shares	Amount				Retained Earnings				Total Equity
Balance at December 31, 2020	200	$	—	$	3,313,532	$	912,787	$	(86,437)	$	4,139,882
Net income (loss)	—	—		—		188,993		—		188,993
Common stock dividend paid	—	—		—		(22,939)		—		(22,939)
Other comprehensive income (loss)	—	—		—		—		2,385		2,385
Balance at March 31, 2021	200	$	—	$	3,313,532	$	1,078,841	$	(84,052)	$	4,308,321
Balance at December 31, 2021	200	$	—	$	3,523,532	$	1,067,216	$	(27,432)	$	4,563,316
Net income (loss)	—	—		—		278,295		—		278,295
Common stock dividend paid	—	—		—		(939)		—		(939)
Other comprehensive income (loss)	—	—		—		—		1,831		1,831
Balance at March 31, 2022	200	$	—	$	3,523,532	$	1,344,572	$	(25,601)	$	4,842,503

The accompanying notes are an integral part of the consolidated financial statements.

8

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Operating activities:
Net Income (loss)	$	278,295	$	188,993
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	164,576		208,431
Conservation amortization	30,141		34,060
Deferred income taxes and tax credits, net	(3,641)		6,622
Net unrealized (gain) loss on derivative instruments	(131,921)		(23,002)
AFUDC - equity	(6,971)		(5,780)
Production tax credit utilization	—		(45,178)
Other non-cash	2,326		3,518
Regulatory assets and liabilities	4,470		(14,351)
Purchased gas adjustment	13,915		40,868
Other long term assets and liabilities	(7,891)		(5,695)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	35,847		(19,743)
Materials and supplies	(7,077)		442
Fuel and natural gas inventory	12,033		10,052
Prepayments and other	(4,733)		(3,884)
Accounts payable	(57,324)		(14,868)
Taxes payable	41,726		23,476
Other	18,615		(512)
Net cash provided by (used in) operating activities	382,386		383,449
Investing activities:
Construction expenditures - excluding equity AFUDC	(233,131)		(213,781)
Other	(532)		362
Net cash provided by (used in) investing activities	(233,663)		(213,419)
Financing activities:
Change in short-term debt, net	(70,250)		(182,800)
Dividends paid	(939)		(22,939)
Proceeds from long-term debt and bonds issued	448,075		8,800
Redemption of bonds and notes	—		(66)
Other	5,523		6,074
Net cash provided by (used in) financing activities	382,409		(190,931)
Net increase (decrease) in cash, cash equivalents, and restricted cash	531,132		(20,901)
Cash, cash equivalents, and restricted cash at beginning of period	103,150		81,851
Cash, cash equivalents, and restricted cash at end of period	$	634,282	$	60,950
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	65,238	$	77,160
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	61,133	$	54,805

The accompanying notes are an integral part of the financial statements.

9

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Operating revenue:
Electric	$	756,377	$	758,592
Natural gas	426,348		392,906
Other	10,677		8,588
Total operating revenue	1,193,402		1,160,086
Operating expenses:
Energy costs:
Purchased electricity	238,203		205,410
Electric generation fuel	60,644		60,418
Residential exchange	(23,070)		(25,802)
Purchased natural gas	177,333		155,015
Unrealized (gain) loss on derivative instruments, net	(131,921)		(23,002)
Utility operations and maintenance	170,300		160,540
Non-utility expense and other	12,814		9,418
Depreciation & amortization	163,704		208,362
Conservation amortization	30,141		34,060
Taxes other than income taxes	121,116		110,310
Total operating expenses	819,264		894,729
Operating income (loss)	374,138		265,357
Other income (expense):
Other income	10,968		11,034
Other expense	(3,154)		(1,510)
Interest charges:
AFUDC	4,129		3,586
Interest expense	(63,144)		(62,371)
Income (loss) before income taxes	322,937		216,096
Income tax (benefit) expense	34,856		16,626
Net income (loss)	$	288,081	$	199,470

The accompanying notes are an integral part of the financial statements.

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Net income (loss)	$	288,081	$	199,470
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $953 and $1,185, respectively	3,588		4,458
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $26, respectively	97		96
Other comprehensive income (loss)	3,685		4,554
Comprehensive income (loss)	$	291,766	$	204,024

The accompanying notes are an integral part of the financial statements.

11

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	March 31, 2022		December 31, 2021
Utility plant (at original cost, including construction work in progress of $696,617 and $870,204, respectively):
Electric plant	$	11,633,462	$	11,535,976
Natural gas plant	5,109,791		5,054,622
Common plant	1,142,049		1,177,598
Less:  Accumulated depreciation and amortization	(6,449,342)		(6,416,246)
Net utility plant	11,435,960		11,351,950
Other property and investments:
Other property and investments	76,507		74,602
Total other property and investments	76,507		74,602
Current assets:
Cash and cash equivalents	150,893		50,043
Restricted cash	30,525		46,204
Accounts receivable, net of allowance for doubtful accounts of $41,233 and $34,958, respectively	420,726		402,602
Unbilled revenue	215,299		271,606
Materials and supplies, at average cost	120,364		113,287
Fuel and natural gas inventory, at average cost	45,795		58,129
Unrealized gain on derivative instruments	293,884		128,210
Prepaid expense and other	50,906		46,293
Total current assets	1,328,392		1,116,374
Other long-term and regulatory assets:
Power cost adjustment mechanism	67,808		79,546
Purchased gas adjustment receivable	44,020		57,935
Other regulatory assets	809,414		815,058
Unrealized gain on derivative instruments	36,690		26,197
Operating lease right-of-use asset	182,077		184,957
Other	164,477		162,391
Total other long-term and regulatory assets	1,304,486		1,326,084
Total assets	$	14,145,345	$	13,869,010

The accompanying notes are an integral part of the financial statements.

12

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	March 31, 2022		December 31, 2021
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859	$	859
Additional paid-in capital	3,485,105		3,485,105
Retained earnings	1,256,792		982,607
Accumulated other comprehensive income (loss), net of tax	(109,456)		(113,141)
Total common shareholder’s equity	4,633,300		4,355,430
Long-term debt:
First mortgage bonds and senior notes	4,662,000		4,662,000
Pollution control bonds	161,860		161,860
Debt discount, issuance costs and other	(38,629)		(39,141)
Total long-term debt	4,785,231		4,784,719
Total capitalization	9,418,531		9,140,149
Current liabilities:
Accounts payable	379,918		451,716
Short-term debt	69,750		140,000
Accrued expenses:
Taxes	180,568		133,406
Salaries and wages	43,489		47,936
Interest	58,264		51,832
Unrealized loss on derivative instruments	40,237		63,309
Operating lease liabilities	20,624		20,398
Other	87,814		62,406
Total current liabilities	880,664		971,003
Other long-term and regulatory liabilities:
Deferred income taxes	1,104,851		1,084,203
Unrealized loss on derivative instruments	22,373		40,965
Regulatory liabilities	929,110		842,920
Regulatory liabilities for deferred income tax	852,842		866,541
Operating lease liabilities	168,637		172,510
Finance lease liabilities	104,539		105,303
Other deferred credits	663,798		645,416
Total long-term and regulatory liabilities	3,846,150		3,757,858
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	14,145,345	$	13,869,010

The accompanying notes are an integral part of the financial statements.

13

 PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

(Unaudited)

	Common Stock			Additional Paid-in Capital				Accumulated Other Comprehensive Income (Loss)
	Shares	Amount				Retained Earnings				Total Equity
Balance at December 31, 2020	85,903,791	$	859	$	3,485,105	$	876,401	$	(180,956)	$	4,181,409
Net income (loss)	—	—		—		199,470		—		199,470
Common stock dividend paid	—	—		—		(52,053)		—		(52,053)
Other comprehensive income (loss)	—	—		—		—		4,554		4,554
Balance at March 31, 2021	85,903,791	$	859	$	3,485,105	$	1,023,818	$	(176,402)	$	4,333,380
Balance December 31, 2021	85,903,791	$	859	$	3,485,105	$	982,607	$	(113,141)	$	4,355,430
Net income (loss)	—	—		—		288,081		—		288,081
Common stock dividend paid	—	—		—		(13,896)		—		(13,896)
Other comprehensive income (loss)	—	—		—		—		3,685		3,685
Balance March 31, 2022	85,903,791	$	859	$	3,485,105	$	1,256,792	$	(109,456)	$	4,633,300

The accompanying notes are an integral part of the consolidated financial statements.

14

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2022		2021
Operating activities:
Net Income (loss)	$	288,081	$	199,470
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	163,704		208,362
Conservation amortization	30,141		34,060
Deferred income taxes and tax credits, net	5,970		21,044
Net unrealized (gain) loss on derivative instruments	(131,921)		(23,002)
AFUDC - equity	(6,971)		(5,780)
Production tax credit utilization	—		(45,178)
Other non-cash	(328)		885
Regulatory assets and liabilities	4,470		(14,351)
Purchased gas adjustment	13,915		40,868
Other long term assets and liabilities	(5,558)		(3,077)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	38,183		(17,957)
Materials and supplies	(7,077)		442
Fuel and natural gas inventory	12,334		10,052
Prepayments and other	(4,733)		(3,884)
Accounts payable	(61,531)		(14,853)
Taxes payable	47,162		23,527
Other	11,300		3,549
Net cash provided by (used in) operating activities	397,141		414,177
Investing activities:
Construction expenditures - excluding equity AFUDC	(232,868)		(205,927)
Other	(532)		362
Net cash provided by (used in) investing activities	(233,400)		(205,565)
Financing activities:
Change in short-term debt, net	(70,250)		(182,800)
Dividends paid	(13,896)		(52,053)
Redemption of bonds and notes	—		(66)
Other	5,576		6,080
Net cash provided by (used in) financing activities	(78,570)		(228,839)
Net increase (decrease) in cash, cash equivalents, and restricted cash	85,171		(20,227)
Cash, cash equivalents, and restricted cash at beginning of period	96,247		80,721
Cash, cash equivalents, and restricted cash at end of period	$	181,418	$	60,494
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	51,357	$	47,749
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	61,133	$	54,805

The accompanying notes are an integral part of the financial statements.

15

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1)Summary of Consolidation and Significant Accounting Policy

Basis of Presentation

Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Allowance for Credit Losses

Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, natural gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.

The allowance increased during both periods due to both an increase in the provision combined with a reduction in receivables charged-off during the period. The Ratepayer Assistance and Preservation of Essential Services proclamation issued by the Washington State governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment. This moratorium ended on September 30, 2021, however, customer disconnects are only performed with approval from the WUTC.

The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2022 and 2021:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021
Allowance for credit losses:
Beginning balance	$	34,958	$	20,080
Provision for credit loss expense 1	9,767		12,452
Receivables charged-off	(3,492)		(2,140)
Total ending allowance balance	$	41,233	$	30,392

_______________

1 $4.7 million and $0.0 million of provision were deferred as cost specific to COVID-19 for the three months ended March 31, 2022 and 2021, respectively.

16

Tacoma LNG Facility

On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and provide LNG as fuel to transportation customers, particularly in the marine market at a lower cost due to the facility's scale.

Pursuant to an order by the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $244.8 million and $244.7 million of non-utility plant and construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" line item as of March 31, 2022 and December 31, 2021, respectively. Additionally, $2.2 million and $0.2 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for the three months ended March 31, 2022, and March 31, 2021, respectively. Further, $241.7 million and $239.6 million of natural gas plant and construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of March 31, 2022 and December 31, 2021, respectively, as PSE is a regulated entity.

Variable Interest Entities

On April 12, 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy certificates (RECs) to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Skookumchuck is a variable interest entity (VIE) and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $3.9 million and $5.7 million were recognized in purchased electricity on the Company's consolidated statements of income for the three months ended March 31, 2022 and March 31, 2021, respectively. Additionally, $2.7 million was included in accounts payable on the Company's balance sheet as of both March 31, 2022 and December 31, 2021.

On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE.

(2)  New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued Accounting Standards Update (ASU) 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020). ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of March 31, 2022, the Company has not utilized any of the expedients discussed within this ASU; however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.

17

(3) Revenue

The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended March 31, 2022 and March 31, 2021:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2022
Revenue from contracts with customers:	Electric		Natural Gas		Other1		Total
Retail
Residential	$	416,260	$	292,596	$	—	$	708,856
Commercial	257,019		120,979		—		377,998
Industrial	30,073		8,085		—		38,158
Other	4,761		—		—		4,761
Wholesale	13,147		—		—		13,147
Transmission and transportation	11,222		5,446		—		16,668
Miscellaneous	1,150		309		10,712		12,171
Total revenue from contracts with customers	$	733,632	$	427,415	$	10,712	$	1,171,759
Total other revenue2	22,745		(1,067)		—		21,678
Total operating revenue	$	756,377	$	426,348	$	10,712	$	1,193,437

_____________

1 Other includes $0.1 million of Puget LNG revenues recorded at Puget Energy.

2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2021
Revenue from contracts with customers:	Electric		Natural Gas		Other		Total
Retail
Residential	$	401,510	$	276,687	$	—	$	678,197
Commercial	229,639		103,387		—		333,026
Industrial	27,533		7,535		—		35,068
Other	5,420		254		—		5,674
Wholesale	23,676		—		—		23,676
Transmission and transportation	9,226		5,161		—		14,387
Miscellaneous	8,401		1,077		8,588		18,066
Total revenue from contracts with customers	$	705,405	$	394,101	$	8,588	$	1,108,094
Total other revenue1	53,187		(1,195)		—		51,992
Total operating revenue	$	758,592	$	392,906	$	8,588	$	1,160,086

_____________

1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.

18

Transaction Price Allocated to Remaining Performance Obligations

In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:

Puget Energy
(Dollars in Thousands)	2024		2025		2026		2027		2028		Thereafter		Total
Remaining Performance Obligations	$	15,359	$	19,710	$	19,454	$	19,454	$	19,454	$	102,135	$	195,566

The Company has elected the optional exemption in ASC 606, under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. The primary sources of variability are (a) fluctuations in market index prices of natural gas used to determine aspects of variable pricing and (b) variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG or natural gas. As each unit of LNG or natural gas represents a separate performance obligation, future volumes are wholly unsatisfied.

19

(4) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus, reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy, which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.

The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy
	March 31, 2022					December 31, 2021
(Dollars in Thousands)	Volumes (millions)	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	173,481	$	52,154	*	$	74,829	$	85,424
Natural gas derivatives (MMBtus)3	320	157,093		10,456		347	79,578		18,850
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274
Current		$	293,884	$	40,237		$	128,210	$	63,309
Long-term		36,690		22,373			26,197		40,965
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274

_______________

1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.

2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

* Electric portfolio derivatives consist of electric generation fuel of 231.2 million British Thermal Units (MMBtu) and purchased electricity of

6.0 million Megawatt Hours (MWhs) at March 31, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report.

20

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
	At March 31, 2022
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	330,574	$	—	$	330,574	$	(31,515)	$	—	$	299,059
Liabilities:
Energy derivative contracts	$	62,610	$	—	$	62,610	$	(31,515)	$	—	$	31,095

Puget Energy and Puget Sound Energy	At December 31, 2021
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	154,407	$	—	$	154,407	$	(40,833)	$	—	$	113,574
Liabilities:
Energy derivative contracts	$	104,274	$	—	$	104,274	$	(40,833)	$	(1,743)	$	61,698

_______________

1 All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.    

21

The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy and Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Classification	2022		2021
Gas for power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	86,873	$	1,628
Realized	Electric generation fuel	27,091		8,313
Power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	45,048		21,374
Realized	Purchased electricity	2,591		(13,303)
Total gain (loss) recognized in income on derivatives		$	161,603	$	18,012

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation.

The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of March 31, 2022, approximately 99.4% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.6% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE natural gas exchange (NGX) platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2022, PSE had cash posted as collateral of $6.1 million related to contracts executed on the ICE platform. Also, as of March 31, 2022, PSE had $17.0 million in cash posted as collateral and no letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended March 31, 2022.

22

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At March 31, 2022						At December 31, 2021
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	23,484	$	—	$	23,484	$	52,537	$	—	$	52,537
Requested credit for adequate assurance	7,024		—		—		9,380		—		—
Forward value of contract3	—		—		N/A		1,743		12,782		N/A
Total	$	30,508	$	—	$	23,484	$	63,660	$	12,782	$	52,537

_______________

1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts

payable and accounts receivable.

2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to

demand collateral.

3 Collateral requirements may vary based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

(5) Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy 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. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department, which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.

The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes or that are transacted at illiquid delivery

23

locations are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $53.4 million and $53.2 million at March 31, 2022 and December 31, 2021 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,620,643	$	7,338,267	$	6,170,466	$	7,769,896
Long-term debt (variable-rate)	2	34,300		34,300		33,300		33,300
Total liabilities		$	6,654,943	$	7,372,567	$	6,203,766	$	7,803,196

Puget Sound Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639
Total liabilities		$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639

_______________

1 The carrying value includes debt issuances costs of $22.1 million and $22.7 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.5 million and $22.8 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

24

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:

Puget Energy and Puget Sound Energy	Fair Value At March 31, 2022						Fair Value At December 31, 2021
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	160,220	$	13,261	$	173,481	$	68,011	$	6,818	$	74,829
Natural gas derivative instruments	156,674		419		157,093		79,526		52		79,578
Total assets	$	316,894	$	13,680	$	330,574	$	147,537	$	6,870	$	154,407
Liabilities:
Electric derivative instruments	$	32,883	$	19,271	$	52,154	$	35,854	$	49,570	$	85,424
Natural gas derivative instruments	8,825		1,631		10,456		16,678		2,172		18,850
Total liabilities	$	41,708	$	20,902	$	62,610	$	52,532	$	51,742	$	104,274

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022						2021
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	38,820		—		38,820		820		—		820
Included in regulatory assets / liabilities	—		415		415		—		(888)		(888)
Settlements	(2,254)		324		(1,930)		1,728		189		1,917
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	176		169		345		—		—		—
Balance at end of period	$	(6,010)	$	(1,212)	$	(7,222)	$	(21,170)	$	(1,834)	$	(23,004)

_______________

1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $38.6 million and $0.8 million for three months ended March 31, 2022 and 2021, respectively.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.

The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and gas commodity contracts, respectively, as of the reporting date.

25

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2022:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	13,261	$	19,271	Discounted cash flow	Power prices (per MWh)	$	28.75	$	161.09	$	76.95
Natural gas	$	419	$	1,631	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.99	$	6.44	$	5.55

_______________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2021:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	6,818	$	49,570	Discounted cash flow	Power prices (per MWh)	$	21.88	$	119.38	$	61.51
Natural gas	$	52	$	2,172	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.65	$	7.54	$	5.89

___________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of March 31, 2022, and December 31, 2021, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $20.3 million and $17.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.

As of March 31, 2022, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and determined that no impairment was needed. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and liabilities were revalued in accordance with ASC 805, "Business Combinations."

26

(6) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new UA represented employees hired or rehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible pay each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Plan) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020.

Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income.

For further information, see Note 13, "Retirement Benefits" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2021.

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2022 and 2021:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(476)		72		87		6		2
Amortization of net loss (gain)	1,628		2,830		618		587		(4)		(10)
Net periodic benefit cost	$	1,735	$	2,562	$	1,142	$	1,082	$	39	$	19

27

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(378)		72		87		6		2
Amortization of net loss (gain)	3,806		5,311		663		635		(6)		(15)
Net periodic benefit cost	$	3,913	$	5,141	$	1,187	$	1,130	$	37	$	14

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2022 and December 31, 2021:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended		Year Ended		Three Months Ended		Year Ended		Three Months Ended		Year Ended
(Dollars in Thousands)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Change in benefit obligation:
Benefit obligation at beginning of period	$	834,960	$	849,383	$	43,155	$	46,742	$	11,654	$	12,114
Amendments	—		—		—		—		—		205
Service cost	6,797		26,888		139		456		55		155
Interest cost	6,087		22,381		313		1,183		81		302
Actuarial loss (gain)	—		(6,826)		—		828		—		(514)
Benefits paid	(11,723)		(55,831)		(494)		(6,054)		(227)		(803)
Medicare part D subsidy received	—		—		—		—		—		195
Administrative Expense	—		(1,035)		—		—		—		—
Benefit obligation at end of period	$	836,121	$	834,960	$	43,113	$	43,155	$	11,563	$	11,654

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2022, are expected to be at least $18.0 million, $2.8 million and $0.3 million, respectively. The Company contributed $0.5 million to fund the SERP during the three months ended March 31, 2022 and 2021. The Company contributed an immaterial amount to fund the other postretirement plans.

28

(7) Regulation and Rates

General Rate Case

PSE filed a general rate case (GRC) which includes a three year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by Revised Code of Washington (RCW) 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. The Washington Commission issued a procedural schedule and the case is pending. The Company cannot predict the outcome of the case at this time.

PSE filed a GRC with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.05%, and the natural gas increase to $1.3 million, or 0.15%, and became effective October 15, 2020 and October 1, 2020, respectively.

On July 30, 2021, the IRS issued a Private Letter Ruling (PLR) to PSE which concluded that in the 2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. The PLR required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. Accordingly, on September 28, 2021, the Washington Commission issued an order amending their order previously issued on July 8, 2020, to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed in the PLR. To reflect the impact of the PLR, PSE recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021. The annualized overall rate impact is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

Power Cost Only Rate Case

On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).

On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021.

Decoupling Filings

On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and fixed power cost sections originally filed through the annual May 2020 decoupling filing. The extension requires PSE to move amortization balances for electric decoupling as of August 31, 2020 to be collected from customers for a two-year period, instead of the originally approved one-year period. Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups.

29

On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On June 1, 2021, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.

On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.

On March 31, 2022, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2022 electric or natural gas decoupling revenue. At March 31, 2021, the analysis estimated $0.9 million of electric deferred revenue not to be collected within 24 months of the annual period in 2021; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. At March 31, 2021, natural gas deferred revenue was estimated to be collected within 24 months of the annual period in 2021; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue.

Power Cost Adjustment Mechanism

PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.

Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:

	Company’s Share				Customers' Share
Annual Power Cost Variability	Over		Under		Over		Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%	—	%
Over or Under Collected by between $17 million - $40 million	35		50		65		50
Over or Under Collected beyond $40 + million	10		10		90		90

For the three months ended March 31, 2022, in its PCA mechanism, PSE under recovered its allowable costs by $10.6 million of which zero was apportioned to customers and $0.3 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $11.4 million for the three months ended March 31, 2021, of which zero was apportioned to customers and accrued $0.3 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing

On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Microsoft Special Contracts, which will be included in allowed rates under the Decoupling Schedule 142 effective October 15, 2020.

PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021.

30

Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On April 30, 2022, PSE filed a 2021 PCA report with the Washington Commission that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.

Purchased Gas Adjustment Mechanism

On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. Those annual 2021 PGA rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.

The following table presents the PGA mechanism balances and activity at March 31, 2022 and December 31, 2021:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	161,647		364,775
Allowed PGA recovery	(175,930)		(396,236)
Interest	368		1,741
PGA receivable ending balance	$	44,020	$	57,935

Get to Zero Depreciation Deferral

On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get to Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. At March 31, 2022 and December 31, 2021, PSE deferred $7.9 million and $6.6 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89%. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's then-next GRC, which PSE filed on January 31, 2022, and is currently pending. Finally, the final order set the rate at which PSE could defer and recover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed CACAP-1 (dockets UE-200331 and UG-200332) with the Washington Commission revisions to its currently effective electric and natural gas service tariffs. The purpose of this filing was to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to September 30, 2020.

31

On March 28, 2021, the Washington Commission approved PSE’s CACAP-2 (dockets UE-210137 and UG-210138), effective April 12, 2021. With a program budget of $20.0 million for electric customers and $7.7 million for natural gas customers, CACAP-2 would provide up to $2,500 in bill assistance in arrearages per year for each qualifying low-income household. PSE stopped taking new applications for the COVID-19 Bill Assistance Program at 7:00 AM Pacific Standard Time on March 29, 2022. Estimates indicated that the electric funds would be exhausted once the current applications are completed.

On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (dockets UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program (HELP). With a combined total budget of $34.5 million for both electric and natural gas residential customers (capped at $23.7 million and $10.8 million, respectively). Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an opt-out option, in December 2021. Supplemental CACAP will be administered until funds are exhausted.

Storm Loss Deferral Mechanism

The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the three months ended March 31, 2022, PSE incurred $2.2 million in weather-related electric transmission and distribution system restoration costs, of which zero and $0.1 million was deferred as regulatory assets related to storms that occurred in 2022 and 2021, respectively. This compares to $23.3 million incurred in weather-related electric transmission and distribution system restoration costs for the three months ended March 31, 2021, of which the Company deferred $12.9 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

(8) Commitments and Contingencies

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the 2017 GRC settlement, to December 31, 2027, which was subsequently updated to December 31, 2025 as part of the 2019 GRC. The 2017 GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.

Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On May 19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a lawsuit against the Montana Attorney General challenging the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. As of March 31, 2022, the Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

Other Commitments and Contingencies

There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2021.

32

(9)  Leases

As of March 31, 2022, there have been no material changes regarding the Company's leases. For further information, see Note 9, "Leases" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

(10) Other

Long-Term Debt

On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.

On June 23, 2021, Puget Energy received an equity contribution from Puget Equico, LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan.

On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes.

On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes were issued for a period of 10 years, mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance were used for repayment of Puget Energy notes that mature July 2022 and for general corporate purposes.

On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.

As of March 31, 2022, Puget Energy maintained an $800.0 million credit facility, of which $34.3 million was drawn and outstanding under the facility. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

Short-Term Debt

As of March 31, 2022, no amount was drawn under PSE's credit facility and $69.8 million was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

33

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

The following discussion and analysis is intended to promote understanding of the results of operations and financial condition, is provided as a supplement to, and should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. This section generally discusses the results of operations and changes in financial condition for period ended March 31, 2022 compared to 2021. For discussion related to the results of operations and changes in financial condition for period ended March 31, 2021 compared to 2020 refer to Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our period ended March 31, 2021, Form 10-Q, which was filed with the United States Securities and Exchange commission (SEC). The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2021. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations, including the Coronavirus disease 2019 (COVID-19) pandemic.

34

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its wholly-owned subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility which is under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including the British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. Puget Energy and PSE are collectively referred to herein as “the Company.”

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.

COVID-19 Update

The outbreak of COVID-19 has resulted in a global pandemic. The Company continues to monitor the impact of the pandemic and take steps to mitigate known risks. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions to customers.

Due to business disruptions caused by the COVID-19 pandemic, the Company incurred increased costs and partially offset cost savings. On September 3, 2020, the Company filed an accounting petition with the Washington Commission, requesting authorization to defer the costs and foregone revenue net of offsets associated with the COVID-19 public health emergency. On November 6, 2020, PSE filed a revised petition which was approved on December 10, 2020 by the Washington Commission granting PSE's accounting petition in part by allowing the deferral of COVID-19 incremental costs and foregone revenue net of offsets. As of March 31, 2022, PSE deferred $27.6 million specific to COVID-19 net of offsets.

On March 27, 2020, the U.S. Government enacted the CARES Act, which provided approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 pandemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. Among other provisions, the CARES Act includes modifications to corporate income tax provisions, including temporary suspension of certain payment requirements for the employer portion of social security taxes. As a result of these modifications, the Company deferred payroll taxes totaling $6.8 million as of March 31, 2022.

Further detail regarding the factors and trends affecting performance of the Company during the three months ended March 31, 2022, is set forth below in this "Overview" section as well as in other sections of Management's Discussion and Analysis.

35

Factors and Trends Affecting PSE's Performance

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2022 and will continue to do so in future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process.  The principal business, economic and other factors that affect PSE’s operations and financial performance include:

•The rates PSE is allowed to charge for its services;

•PSE’s ability to recover power costs that are included in rates which are based on volume;

•Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, stream-flow and wind-speed which affect power generation, supply and price;

•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;

•Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;

•PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;

•Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return (ROR);

•Availability and access to capital and the cost of capital;

•Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;

•Wholesale commodity prices of electricity and natural gas;

•Increasing capital expenditures with additional depreciation and amortization;

•Failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;

•Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base and customer rates;

•General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer;

•Federal, state, and local taxes;

•Employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and loss or retirement of key personnel and availability of qualified personnel;

•The effectiveness of PSE’s risk management policies and procedures;

•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;

•Acts of war or terrorism locally or abroad, or the impact of civil unrest to infrastructure or preventing access to infrastructure and its impact on the supply chain and prices of goods and services; and

•Risks due to pandemics, including supply shortages, rising costs, disruption to vendor or customer relationships, the potential for reputational harm, the impact of government, business and company closure of facilities, customer or contract defaults; concerns of safety to employees and customers, potential costs due to quarantining of employees and work-from-home policies, and the Company's and vendor staffing levels resulting from vaccination mandates.

36

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2022 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief through a rate case with the Washington Commission. The Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. The Washington Commission and Washington state law also set natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.

General Rate Case

PSE filed a general rate case (GRC) which includes a three year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by RCW 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. The Washington Commission issued a procedural schedule and the case is pending. The Company cannot predict the outcome of the case at this time.

PSE filed a GRC with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s purchases gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.05% and the natural gas increase to $1.3 million, or 0.15% and became effective October 15, 2020 and October 1, 2020, respectively.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the Internal Revenue Service (IRS) normalization and consistency rules.

PSE requested a Private Letter Ruling (PLR) from the IRS regarding this matter. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement was based on a commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission would open a proceeding to review and enact the changes required by the IRS ruling. There was approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE requested it be allowed to track and recover.

37

On July 30, 2021, the IRS issued a PLR to PSE which concluded that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. On September 28, 2021, the Washington Commission issued an order amending its order previously issued on July 8, 2020 to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed in the PLR. To reflect the impact of the PLR, PSE recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021. The annualized overall rate impact for this element is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to an overall annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to an overall annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

Power Cost Only Rate Case

A power cost only rate case (PCORC) is a limited-scope proceeding to reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission is not required to but historically has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).

On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs and fixed production costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the power cost adjustment (PCA) and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption except for fixed production costs, which are held at the level of cost from the most recent rate proceeding and are not impacted by customer growth. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On June 1, 2021, the Washington Commission approved a multi-party settlement agreement in PSE's PCORC that was originally filed on December 9, 2020. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.

On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.

38

On March 31, 2022, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for U.S. Generally Accepted Accounting Principles (GAAP) purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2022 electric or natural gas decoupling revenue. At March 31, 2021, the analysis estimated $0.9 million of electric deferred revenue not to be collected within 24 months of the annual period in 2021; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. Whereas, at March 31, 2021, natural gas deferred revenue was estimated to be collected within 24 months of the annual period in 2021; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue.

The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)1
Electric:
May 1, 20222	(1.0)%	$(23.5)
May 1, 20213	1.0	21.4
January 1. 2021	(1.0)	(20.6)
October 15, 20204	(0.5)	(10.2)
May 1, 2020	0.2	2.0
Natural Gas:
May 1, 2022	(0.7)%	$(7.4)
May 1, 2021	1.5	15.0
May 1, 2020	(0.5)	(4.8)

__________________

1 For electric and natural gas rates effective May 1, 2022, May 1, 2021 and May 1, 2020, there were no excess earnings that impacted the approved revenue change.

2 For the electric rates effective May 1, 2022, there was $8.0 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2023 due to the 3% rate cap.

3 For the electric rates effective May 1, 2021, there was $24.1 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 202 due to the 3% rate cap.

4 The 2019 GRC final order lengthened the recovery period from the original one-year recovery to a two-year recovery of April 2022. The remaining decoupling amortization balances for delivery and fixed power costs of $1.7 million were included in electric decoupling mechanism tariff rates, effective May 1, 2022.

Electric Rates

Power Cost Adjustment Mechanism

PSE currently has a power cost adjustment (PCA) mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.

Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:

	Company's Share		Customers’ Share
Annual Power Cost Variability	Over	Under	Over	Under
Over or Under Collected by up to $17 million	100%	100%	—%	—%
Over or Under Collected by between $17 million - $40 million	35	50	65	50
Over or Under Collected beyond $40 + million	10	10	90	90

39

For the three months ended March 31, 2022, in its PCA mechanism, PSE under recovered its allowable costs by $10.6 million of which zero was apportioned to customers and $0.3 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $11.4 million for the three months ended March 31, 2021, of which zero was apportioned to customers and $0.3 million of interest was accrued on the total deferred customer balance.

Power Cost Adjustment Clause Filing

PSE updated its Schedule 95 rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.

PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021.

Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On April 30, 2022, PSE filed a 2021 PCA report with the Washington Commission that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.

The following table sets forth power cost adjustment clause filing approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 20201	2.1%	$43.9
October 15, 2020	(0.2)	(3.3)
July 3, 20202	1.2	23.9

______________

1 The Schedule 95 PCA mechanism rates from the prior year that recover the 2019 imbalance (effective December 1, 2020) have been extending through December 31, 2022 to recover the imbalance attributable to 2020.

2 The rates for the Electric Special Contract were zeroed out effective July 3, 2020 following the July 2019 through June 2020 period. The actual residual amount resulting at July 31, 2020 were included in the electric Schedule 129 Low Income Program rates that became effective October 1, 2020.

Conservation Rider

The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.

The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022	1.0%	$21.6
May 1, 2021	(0.6)	(12.3)
May 1, 2020	0.9	17.8

40

Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.

The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022	(0.3)%	$(5.8)
May 1, 2021	(0.1)	(1.7)
May 1, 2020	0.07	1.4

Federal Incentive Tracker Tariff

The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1.

The following table sets forth the federal incentive tracker tariff revenue requirement approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2022	0.1%	$(28.2)
January 1, 2021	0.3	(29.5)
January 1, 2020	(0.04)	(37.8)

Low Income Program Tracker Tariff

The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket No. UE-011570). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 1.

The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
October 1, 2021	0.3%	$5.8

41

Residential Exchange Benefit

The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA). Rates change biennially on October 1.

The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
November 1, 2021	0.4%	$(75.7)
October 12, 2019	0.01	(81.8)

Natural Gas Rates

Conservation Rider

The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.

The following table sets forth conversation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022	0.3%	$3.2
May 1, 2021	(0.2)	(1.5)
May 1, 2020	0.4	3.5

Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.

The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE's revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2022	0.02%	$0.2
May 1, 2021	0.3	3.2
May 1, 2020	(0.3)	(2.8)

Cost Recovery Mechanism

The purpose of the cost recovery mechanism (CRM) is to recover costs related to projects included in PSE's pipeline replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.

42

The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2021	0.5%	$4.9
November 1, 2020	1.2	10.6

Purchased Gas Adjustment

PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the year if needed.

On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million.

The annual 2021 PGA rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.

The following table presents the PGA mechanism balances and activity at March 31, 2022 and December 31, 2021:

(Dollars in Thousands)	March 31,		December 31,
PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	161,647		364,775
Allowed PGA recovery	(175,930)		(396,236)
Interest	368		1,741
PGA receivable ending balance	$	44,020	$	57,935

The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2021	5.8%	$59.1
November 1, 2020	7.7	70.0
October 1, 2020	(3.9)	(35.5)

Low Income Program Tracker Tariff

The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket No. UG-011571). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 1.

43

The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
October 1, 2021	(0.3)%	$(3.0)

Other Proceedings

Voluntary Long-Term Renewable Energy

PSE offers Green Direct to larger customers (aggregated annual loads greater than 10,000 megawatt hours (MWh)) and government customers. The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW which went into operation on November 7, 2020. The project is fully subscribed and the twenty-one customers under phase 1 of the program began taking service in November 2020.

The Washington Commission approved a second phase of the Green Direct product in 2018. The phase 2 project is the 150 MW Lund Hill Solar facility located in Klickitat County, Washington. The solar facility is expected to achieve full commercial operation in 2022 and will serve an additional twenty customers who enrolled in 2018. On March 1, 2021, the associated power purchase agreement went into effect under an interim supply agreement for renewable energy delivered to PSE’s system; and thus, the phase 2 customers began receiving renewable energy under their agreement on March 1, 2021. All Green Direct customers are now receiving a blend of the phase 1 wind and the renewable energy delivered under the phase 2 power purchase agreement.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed CACAP-1 (dockets UE-200331 and UG-200332) with the Washington Commission revisions to its currently effective electric and natural gas service tariffs. The purpose of this filing was to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to September 30, 2020.

On March 28, 2021, the Washington Commission approved PSE’s CACAP-2 (dockets UE-210137 and UG-210138), effective April 12, 2021. With a program budget of $20.0 million for electric customers and $7.7 million for natural gas customers, CACAP-2 would provide up to $2,500 in bill assistance in arrearages per year for each qualifying low-income household. PSE stopped taking new applications for the COVID-19 Bill Assistance Program at 7:00 AM Pacific Standard Time on March 29, 2022. Estimates indicated that the electric funds would be exhausted once the current applications are completed.

On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (dockets UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program (HELP). With a combined total budget of $34.5 million for both electric and natural gas residential customers (capped at $23.7 million and $10.8 million, respectively). Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an opt-out option, in December 2021. Supplemental CACAP will be administered until funds are exhausted.

For additional information, see Note 7, "Regulation and Rates" to the consolidated financial statements included in Item 1 of this report.

44

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to refinance existing or issue new long-term debt, obtain access to new or renew existing credit facilities and could increase the cost of issuing long-term debt and maintaining credit facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or generating capacity acquisitions, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs.

Regulatory Compliance Costs and Expenditures

PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

Compliance with these or other future laws and regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.

Other Challenges and Strategies

Competition

PSE’s electric and natural gas utility retail customers generally do not have the ability to choose their electric or natural gas supplier; therefore, PSE’s business has historically been recognized as a natural and regulated monopoly. However, PSE faces competition from public utility districts and municipalities or efforts by citizens organizing to form such entities that want to establish their own government-owned utility, as a result of which PSE may lose a number of customers. PSE also faces increasing competition for sales to its retail customers through alternative methods of electric energy generation, including solar and other self-generation methods. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the three months ended March 31, 2022 and March 31, 2021.

Non-GAAP Financial Measures - Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.”  Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a presentation that is not defined by GAAP.  The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance.  Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to provide adequate recovery of operating costs, including interest and equity returns.  PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural gas margin measures.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

45

The following table presents operating income and a reconciliation of utility electric and natural gas margins to the most directly comparable GAAP measure, operating income:

Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31,
	2022		2021
Operating income (loss)	$	374,138	$	265,357
Electric operating revenue	756,377		758,592
Purchased electricity	(238,203)		(205,410)
Electric generation fuel	(60,644)		(60,418)
Residential exchange	23,070		25,802
Utility electric margin (non-GAAP)	$	480,600	$	518,566
Natural gas operating revenue	426,348		392,906
Purchased natural gas	(177,333)		(155,015)
Utility natural gas margin (non-GAAP)	$	249,015	$	237,891
Other operating revenue	10,677		8,588
Unrealized gain (loss) on derivative instruments, net	131,921		23,002
Utility operation and maintenance	(170,300)		(160,540)
Non-utility expense and other	(12,814)		(9,418)
Depreciation and amortization	(193,845)		(242,422)
Taxes other than income taxes	(121,116)		(110,310)
Operating income (loss)	$	374,138	$	265,357

46

Electric Margin

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory.

The following chart displays the details of PSE's electric margin changes for the three months ended March 31, 2021 and 2022:

______________

*    Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Three Months Ended March 31, 2021 Compared to 2022

Electric Operating Revenue

Electric operating revenues decreased $2.3 million from the prior year primarily due to a decrease in transportation and other revenues of $37.9 million, a decrease in other decoupling revenue of $9.6 million, and a decrease in sales to other utilities of $3.4 million; partially offset by an increase in electric retail sales of $44.3 million, and an increase in decoupling revenue of $4.3 million . These items are discussed in detail below.

•Electric retail sales increased $44.3 million due to an increase of $41.4 million in rates compared to the prior year and an increase of $3.0 million from an increase in retail electricity usage of 0.5%. The increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent PCORC effective July 1, 2021. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes. The slight increase in retail usage was due to an increase in commercial usage of 3.6%, which was partially offset by a decrease in usage of 1.3% for residential customers. The COVID-19 pandemic caused business shut downs in 2021 resulting in reduced commercial usage. In March 2022, businesses began returning to work resulting in higher commercial usage and lower residential usage for the three months ended March 31, 2022 compared to 2021.

•Sales to other utilities decreased $3.4 million due to lower sales volume of 26.9%, which were the result of decreased volume from PSE's gas-fired generation of 37.0%, driven by decreased value in the market. The decrease was partially offset by a 13.8% increase in market prices driven by an increase in natural gas prices nationwide following constrained supply along with increased demand from overseas markets.

47

•Decoupling revenue increased $4.3 million primarily attributable to a $4.0 million and $0.3 million increase in delivery and fixed production cost deferral revenues, respectively. This was driven mainly by a decrease in average consumption per customer in the current period. This resulted in allowed revenues being greater than actual decoupling deferral revenues in the current year, whereas in the prior year allowed revenues were lower compared to actual revenues.

•Other decoupling revenue decreased $9.6 million primarily due to a $5.4 million increase in year-over-year amortization of prior year undercollections due to an increase in amortization rates. Additionally, there was a $4.2 million decrease related to GAAP alternative revenue program recognition guidelines. As of quarter ended March 31, 2021, there were $8.0 million of deferred 2020 GAAP alternative decoupling revenues that were recognized, which was partially offset by $0.9 million in deferred 2021 GAAP alternative decoupling revenues. As of quarter ended March 31, 2022, there were $3.0 million of deferred 2021 GAAP alternative decoupling revenues that were recognized.

•Transportation and other revenue decreased $37.9 million primarily due to the following: (i) no production tax credit (PTC) deferral revenue for the re-purpose of the PTCs in 2022 compared to $45.2 million in 2021; partially offset by: (ii) an increase in net wholesale non-core gas sales of $13.0 million due to a $14.1 million increase in gains on gas financial hedging transactions due to higher gas prices, which was partially offset by $1.0 million net increase in cost of gas sold. The net increase in cost of gas sold was driven by a $40.9 million increase in sales dollars driven by a 60.9% increase in sales volume and a 53.7% increase in the average price of the non-core gas sold in 2022 compared to 2021. This was offset by a $41.9 million increase in the cost of the gas sold due to the higher volume and a 75.7% increase the average price of non-core gas purchases that were then sold; (ii) amortization of the PLR to offset recovery through rates of $4.8 million as a result of the IRS PLR, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report.

Electric Power Costs

Electric power costs increased $35.7 million primarily due to an increase of $32.8 million of purchased electricity costs and a decrease of $2.7 million of residential exchange credits. These items are discussed in detail below.

•Purchased electricity expense increased $32.8 million due to a 13.6% increase in wholesale electricity purchases and a 2.1% increase in wholesale prices driven by higher pricing trends in 2022 compared to 2021 when prices were down due to higher production, mild weather and a surplus due to decreased demands caused by COVID-19.

•Residential Exchange credits decreased by $2.7 million due to a 0.4% change to the amount of credits to be passed back to customers effective November 1, 2021, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report

48

Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through increases or decreases in the natural gas supply portion of the natural gas service rates to customers based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's margin or net income is not affected by changes under the PGA mechanism because over- and under- recoveries of natural gas costs included in baseline PGA rates are deferred and either refunded to or collected from customers in future periods.

The following chart displays the details of PSE's natural gas margin changes for the three months ended March 31, 2021 and 2022:

______________

*    Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Three Months Ended March 31, 2021 Compared to 2022

Natural Gas Operating Revenue

Natural gas operating revenue increased $33.4 million primarily due to an increase of $34.2 million in total retail sales, an increase of $2.9 million in decoupling revenue and a $1.9 million increase in transportation and other revenue; partially offset by a decrease of $5.6 million in other decoupling revenue. These items are discussed in detail below.

•Natural gas retail sales revenue increased $34.2 million primarily due to an increase in rates of $37.4 million partially offset by a $3.2 million decrease due to a decrease in natural gas load of 0.3%. The increase in rates is due to the PGA increase effective November 1, 2021 and the tariffs effective October 1, 2020 filed pursuant to the Company's 2019 GRC. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes.

49

•Decoupling revenue increased $2.9 million primarily attributable to decreased usage in the current period compared to the same period in 2021, as noted above in the retail revenue section. This resulted in actual natural gas revenues being lower than allowed natural gas revenues in the current period, whereas in the same period in 2021, allowed revenues were closer to actual revenues.

•Other decoupling revenue decreased $5.6 million due to an increase in current period amortization of prior year decoupling revenues compared to the same period in 2021. This is attributable to an increase in amortization rates from increased cumulative deferral revenues to recover from customers.

Natural Gas Energy Costs

•Purchased natural gas expense increased $22.3 million due to an increase in the PGA rates in November 2021 partially offset by a decrease in natural gas usage of 0.3% as stated in the natural gas retail sales section above.

Other Operating Expenses and Other Income (Deductions)

The following chart displays the details of PSE's operating expenses and other income (deductions) for the three months ended March 31, 2021 and 2022:

50

Three Months Ended March 31, 2021 Compared to 2022

•Net unrealized (gain) loss on derivative instruments decreased $108.9 million to a net gain of $131.9 million for the quarter ended March 31, 2022. One of the drivers for the change related to the change in the weighted average forward prices for electric and natural gas. Specifically, electric prices increased 6.0% resulting in a $39.6 million gain for electric. Natural gas prices increased 48.4% resulting in a $104.0 million gain for natural gas. The other driver is related to the net settlements of electric trades previously recorded as $15.9 million in gain and of natural gas trades previously recorded as $18.8 million in gain. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" to the consolidated financial statements included in Item 1 of this report.

•Utility operations and maintenance expense increased $9.8 million primarily due to increases in the following: (i) $4.3 million in regulatory commission and GRC expense, (ii) $3.9 million of administrative and general expenses due to employees returning to work, resumed travel and higher IT costs, (iii) $4.0 million in electric distribution expenses due to higher engineering costs, emergent non-outage and outage repairs, travel and training expenses and residential disconnects and connects, (iv) $1.3 million in natural gas leak inspections and repairs, (v) $1.3 million of pension related expenses and (vi) $1.1 million of Colstrip maintenance expense. These increases were partially offset by decreases of (vii) $6.4 million due to fewer storm events in 2022 and (viii) $1.2 million of injuries and damages expense.

•Non-utility expense and other expense increased $3.4 million primarily due to an increase of $1.7 million related to biogas purchase expense and an increase for the long-term incentive plan of $1.4 million due to estimated performance results, as compared to the prior year.

•Depreciation and amortization expense decreased $48.6 million due to: (i) electric amortization decreased by $44.2 million or 81.1% from 2021. This decrease is primarily driven by $45.2 million less PTC amortization in 2022 as PSE fully utilized its PTC balance in 2021, (ii) common amortization decreased by $6.0 million or 24.5% from 2021, primarily driven by $18.0 million in net retirements of common technology assets, and (iii) conservation amortization decreased by $3.9 million due to a decrease in conservation rider rates effective May 1, 2021, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report. The decreases were partially offset by (iv) natural gas distribution depreciation increased $1.5 million or 4.9% from 2021 primarily due to $19.8 million in net additions in natural gas distribution assets and (v) electric distribution depreciation increased a net of $1.3 million or 3.5% from 2021 due to $38.7 million in net additions of electric distribution assets.

•Taxes other than income taxes increased $10.8 million primarily due to an $5.6 million related to municipal taxes and an increase of $3.3 million related to the state excise tax driven by the increase in retail revenue in 2022 as compared to 2021.

Other Income, Interest Expense and Income Tax Expense    

•Income tax expense increased $18.2 million primarily driven by an increase in pre-tax book income.

51

Puget Energy

Primarily, all operations of Puget Energy are conducted through PSE. Puget Energy's net income (loss) for the three months ended March 31, 2021 and 2022 is as follows:

Three Months Ended March 31, 2021 compared to 2022

Summary Results of Operation

Puget Energy’s net income increased by $89.3 million, which is primarily attributable to an increase in PSE's net income of $88.6 million. Additional drivers include a decrease in interest expense of $4.2 million which is a result of lower interest rates on outstanding debt which was partially offset by an increase in net loss of $2.9 million at PLNG due to additional operational expenses.

Capital Requirements

Contractual Obligations and Commercial Commitments

During the three months ended March 31, 2022, there have been no changes to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.

For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the year ended December 31, 2021.

52

The following are the Company's aggregate availability under commercial commitments as of March 31, 2022:

Puget Energy and Puget Sound Energy	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total		Less than 1 Year		1-3 Years		3-5 Years		Thereafter
Commercial commitments:
PSE revolving credit facility	$	800,000	$	—	$	800,000	$	—	$	—
Inter-company short-term debt	30,000		—		—		—		30,000
Total PSE commercial commitments	830,000		—		800,000		—		30,000
Puget Energy revolving credit facility	765,700		—		765,700		—		—
Less: Inter-company short-term debt elimination	(30,000)		—		—		—		(30,000)
Total Puget Energy commercial commitments	$	1,565,700	$	—	$	1,565,700	$	—	$	—

For further discussion, see Management's Discussion and Analysis, "Financing Program" in Item 2 of this report.

Off-Balance Sheet Arrangements

As of March 31, 2022, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program

The Company’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements, support customer growth and to improve energy system reliability.  The Company adjusted capital expenditures, resulting in a decrease of $23.8 million compared to forecasted amounts for the three months ended March 31, 2022. The decrease was primarily due to (i) project and permitting delays for the Lower Baker Dam grouting project, which is being pursued in order to comply with the Federal Energy Regulatory Commission (FERC) dam safety standards and to extend the life of the project to meet the 50 year FERC license; (ii) timing related variances with IT Data Center hardware refresh, and (iii) timing of the Dupont pipe replacement program. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $233.1 million for the three months ended March 31, 2022. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Millions)	2022	2023	2024
Total energy delivery, technology and facilities expenditures	$973.9	$1,293.1	$1,292.1

The program is subject to change based upon general business, economic and regulatory conditions.  Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources which may include cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  

53

Capital Resources

Cash from Operations

Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		Change
Net income	$	288,081	$	199,470	$	88,611
Non-cash items1	60,595		190,391		(129,796)
Changes in cash flow resulting from working capital2	35,638		876		34,762
Regulatory assets and liabilities	4,470		(14,351)		18,821
Purchased gas adjustment	13,915		40,868		(26,953)
Other non-current assets and liabilities3	(5,558)		(3,077)		(2,481)
Net cash provided by operating activities	$	397,141	$	414,177	$	(17,036)

_______________

1 Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and

other miscellaneous non-cash items.

2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayment, PGA, accounts

payable and accrued expenses.

3 Other non-current assets and liabilities include funding of pension liability.

Three Months Ended March 31, 2022 compared to 2021

Cash generated from operations for the three months ended March 31, 2022 decreased by $17.0 million including a net income increase of $88.6 million. The following are significant factors that impacted PSE's cash flows from operations:

•Cash flow adjustments resulting from non-cash items decreased $129.8 million primarily due to a $108.9 million change from a net unrealized gain on derivative instruments of $23.0 million to a net unrealized gain on derivative instruments of $131.9 million, a decrease in depreciation and amortization of $44.7 million, a decrease in conservation amortization of $3.9 million, deferred income taxes of $15.1 million and equity AFUDC of $1.2 million; partially offset by a $45.2 million change in PTC utilization. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2 of this report.

•Cash flows resulting from changes in working capital increased $34.8 million primarily due to the change in accounts receivable, which contributed to a cash inflow of $56.1 million. Accounts receivable decreased $38.1 million in the three months ended March 31, 2022 compared to an increase of $18.0 million during the same period of 2021. Additionally, increased taxes payable added cash inflow of $23.6 million. The cash inflows were partially offset by $46.7 million cash outflow in accounts payable and $1.8 million increase in accrued expenses.

•Cash flows resulting from regulatory assets and liabilities increased $18.8 million primarily due a deferral of $12.9 million of storm excess costs in 2021. Amortizing IRS PLR deferral balances contributed an addition of $5.9 million cash inflow, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report.

•Cash flow resulting from purchased gas adjustment decreased $27.0 million, which was driven by an increase in actual gas cost that exceeded the increase in allowed PGA recovery in 2022 compared to 2021. Increased natural gas prices led to a $48.4 million (or 42.8%) increase in actual gas costs in 2022 compared to 2021. Meanwhile, the total amount of allowed PGA recovery in 2022 increased only $21.4 million (or 13.8%) compared to 2021. The combined effect led to year-over-year cash outflow.

•Cash flows resulting from changes in other non-current assets and liabilities decreased $2.5 million primarily driven by a decrease of $1.7 million due to a lower accrual of liability reserve.

54

Puget Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		Change
Net income	$	(9,786)	$	(10,477)	$	691
Non-cash items1	(6,085)		(11,720)		5,635
Changes in cash flow resulting from working capital2	3,449		(5,913)		9,362
Other non-current assets and liabilities3	(2,333)		(2,618)		285
Net cash provided by operating activities	$	(14,755)	$	(30,728)	$	15,973

_______________

1 Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and

other miscellaneous non-cash items.

2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, PGA, accounts payable and accrued expenses.

3 Other noncurrent assets and liabilities include funding of pension liability.

Three Months Ended March 31, 2022 compared to 2021

Cash generated from operations for the three months ended March 31, 2022, in addition to the changes discussed at PSE above, increased by $16.0 million compared to the same period in 2021, which includes a net income increase of $0.7 million.  The remaining change was primarily impacted by the factors explained below:

•Non-cash items increased $5.6 million primarily due to higher non-cash inflows of $4.8 million related to changes in deferred taxes and an increase in amortization and depreciation of $0.8 million.

•Cash flow resulting from working capital increased $9.4 million primarily due to a $11.4 million increase related to changes in interest accrual for debts at PE. In addition, a $3.7 million increase was caused by the change in PSE's intercompany account receivable and account payable balances with Puget LNG and Puget Energy, which are eliminated upon consolidation of Puget Energy. Cash inflows were partially offset by increased cash outflow of $5.4 million in tax payable and lower other accrued expenses of $0.3 million.

Financing Program

The Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs.  The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its credit facilities and/or the issuance of new long-term debt.  Access to funds depends upon factors such as Puget Energy’s and PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy and PSE. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets to fund its needs over the next twelve months.

Proceeds from PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs.  Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

As a result of the COVID-19 pandemic and its impact on the economy and capital markets, the Company continues to carefully monitor cash receipts from customers and any impacts on the Company’s liquidity which may affect its ability to fund safe, reliable, and dependable service for our customers. Our initiative to suspend disconnections of customers for non-payment and the receipt of the Washington Commission approval to waive late fees will impact future cash receipts.

As a result of the 2019 GRC outcome and the continuing negative impacts of tax reform on the Company's cash flows, Puget Energy and PSE's credit rating metrics were negatively impacted. In response to the 2019 GRC order, Moody's released an issuer comment stating the GRC outcome was credit negative but took no formal credit rating action. On July 23, 2020, S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome, but later revised to negative outlook. Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. On May 27, 2021, S&P revised Puget Energy’s and PSE’s ratings from negative to stable outlook. On June 1, 2021, Fitch also revised its outlook for PE and PSE to stable. Both actions were a result of the passage and signing into law of Washington Senate Bill 5295 which allows for multi-year rate plans and reduction of regulatory lag, as well as other actions taken by management to increase revenue via available rate recovery methods and management of internal expenses. Despite these actions, the rating agencies noted that a lack of sufficient regulatory rate relief over the relative near term could result in negative ratings implications. Although neither Puget Energy nor PSE have any debt whose maturity would be accelerated upon a ratings downgrade, a credit rating downgrade may increase the cost of borrowing for Puget Energy and PSE in future long-term

55

financings or under their existing credit facilities. Any increase in the cost of borrowing may negatively impact Puget Energy and PSE's future results of operations and could negatively impact their future liquidity, access to debt capital resources and financial condition. Additionally, a ratings downgrade could impact the Company's ability to issue dividends, see Dividend Payment Restriction below for further details. A downgrade to Puget Energy and PSE's credit ratings would not impact debt covenants under our existing credit facilities nor would it impact other contracts, as neither include credit rating triggering event clauses. A credit rating decrease for PSE could result in increased cash collateral required for commodity contracts, which would adversely affect PSE's liquidity. Management continually monitors the credit rating environment for both Puget Energy and PSE, but cannot predict with certainty the actions credit agencies may take, if any, in response to weaker near term credit metrics, regulatory and rate recovery uncertainties, and management's efforts to contain the growth of capital and operating expenditures. Containing the growth of capital and operating expenditures will be limited, over the near to medium term, due to continuing strategic and risk mitigation imperatives and the necessity of providing safe, reliable and resilient service levels to customers, particularly in the context of the COVID-19 pandemic.

Puget Sound Energy

Credit Facility

As of March 31, 2022, PSE had an $800.0 million credit facility to meet short-term liquidity needs. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. The unsecured revolving credit facility matures in October 2023.

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0% or less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of March 31, 2022, PSE was in compliance with all applicable covenant ratios.

The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of March 31, 2022, no amount was drawn under PSE's credit facility and $69.8 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.5 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note

In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of March 31, 2022, PSE had no outstanding balance under the Note.

Debt Restrictive Covenants

The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.

PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests at March 31, 2022, PSE could issue:

•Approximately $1.7 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $2.9 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at March 31, 2022; and

•Approximately $919.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.5 billion of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at March 31, 2022.

56

At March 31, 2022, PSE had approximately $8.4 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations

In 2019, PSE filed a new shelf registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $100.0 million was available to be issued. The shelf registration will expire in August 2022.

Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At March 31, 2022, approximately $1.3 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Beginning February 6, 2009, pursuant to the terms of the merger order by the Washington Commission, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 48.8% at March 31, 2022, and the EBITDA to interest expense was 5.3 to 1.0 for the twelve months ended March 31, 2022.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. At March 31, 2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Long Term Debt

On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

Puget Energy

Credit Facility

At March 31, 2022, Puget Energy maintained an $800.0 million credit facility. The Puget Energy revolving senior secured credit facility also has an accordion feature, upon the banks' approval, would increase the size of the facility to $1.3 billion. The revolving credit facility matures in October 2023.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of March 31, 2022, there was $34.3 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0% or less at all times. As of March 31, 2022, Puget Energy was in compliance with all applicable covenants.

57

Shelf Registrations

On March 10, 2022, Puget Energy filed an S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by Puget Energy's assets. As of the date of this report, $550.0 million was available to be issued. The shelf registration will expire in March 2025.

Long-Term Debt

On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15 of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.

On June 23, 2021, Puget Energy received an equity contribution from Puget Equico, LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan on June 23, 2021.

On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes were issued for a period of 10 years, mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance were used for repayment of Puget Energy notes that mature July 2022 and for general corporate purposes.

On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.

For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission in 2009.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.8 to 1.0 for the twelve months ended March 31, 2022.

At March 31, 2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Other

New Accounting Pronouncements

For the discussion of new accounting pronouncements, see Note 2, "New Accounting Pronouncements" to the consolidated financial statements in Item I of this report.

Washington Clean Energy Transformation Act

In May 2019, Washington State passed the Clean Energy Transformation Act (CETA) that supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The CETA requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean energy implementation plans are required every four years from each investor-owned utility (IOU) and must propose interim targets for meeting the 2045 standard between 2030 and 2045, and describe an actionable plan that the IOU intends to pursue to meet the standard. The Washington Commission may approve, reject or recommend alterations to an IOU’s plan.

In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive-based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those facilities. IOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPAs) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.

IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather-adjusted sales revenue to customers from the previous year. If relying

58

on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.

The law requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time. The Company intends to seek recovery of any costs associated with the clean energy legislation through the regulatory process.

Colstrip 

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the 2017 GRC settlement, to December 31, 2027, which was subsequently updated to December 31, 2025 as part of the 2019 GRC. The 2017 GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.

Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington CETA requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On May 19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a lawsuit against the Montana Attorney General challenging the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. As of March 31, 2022, the Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

Washington Climate Commitment Act

In 2021, the Washington Legislature adopted the Climate Commitment Act, which establishes a greenhouse gases (GHG) emissions cap-and-invest program that will take effect on January 1, 2023. The Washington Department of Ecology is currently developing regulations to implement the program, but in general, the program will require covered entities to obtain emission allowances or offset credits for covered emissions.

The Climate Commitment Act will regulate PSE both as an electric utility and as a natural gas distribution utility. PSE will be required to obtain emission allowances or offset credits for GHG emissions associated with electricity generated or imported into the state if the emissions associated with this generation exceed 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s CETA, which is discussed above, PSE will receive some emission allowances at no cost through 2050 to mitigate impacts to ratepayers. PSE will also be required to obtain emission allowances for GHG emissions associated with natural gas supplied to customers, and will receive some emission allowances at no cost on a declining basis to mitigate rate impacts to certain customers. The Department of Ecology’s implementing regulations are expected to be finalized later this year.

Related Party Transactions

In August 2015, PSE filed a proposal with the Washington Commission to develop a liquefied nature gas (LNG) facility at the Port of Tacoma. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. Following a mediation process and the filing of a settlement stipulation by PSE and all parties, the Washington Commission issued an order on October 31, 2016, that allowed PSE’s parent company, Puget Energy, to create a wholly-owned subsidiary, named Puget LNG, which was formed on November 29, 2016, for the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility. Puget LNG has entered into one fuel supply agreement with a maritime customer and is marketing the facility’s expected output to other potential customers.

On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations in February 2022. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. Per this allocation of costs, $244.8 million of non-utility plant and $2.2 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility

59

expense and other" financial statement line items, respectively, as of March 31, 2022. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.

Integrated Resource Plans, Resource Acquisition and Development

On April 1, 2021, the Company filed the final 2021 IRP and the 2021 Request for Proposals for All Resources (All-source RFP), and has since received a number of bids, which the Company is currently evaluating. Bidders have informed the Company that prices are being impacted by substantial inflationary pressure, resulting in higher proposed prices for energy than anticipated. While the current estimates related to RFP bids have no direct financial impact, the Company continues to monitor the impacts of inflation and market pricing pressures on future energy needs.

For further information, see Part I, Item I - “Integrated Resource Plans, Resource Acquisition and Development” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

Human Capital

Information regarding the Company’s human capital measures and objectives is contained in the Environmental, Social and Governance (ESG) report that can be found on the Company’s website, www.pse.com. The information on the Company’s website is not, and will not be deemed to be a part of this Quarterly Report on Form 10-Q or incorporated into the Company’s other filings with the SEC.

Item 3.     Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

Commodity Price Risk

The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.    

PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  

Counterparty Credit Risk

PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. PSE manages credit risk with policies and procedures for counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB)) with its counterparties to mitigate credit exposure.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. During periods of financial market or interest rate volatility, the Company may utilize its credit facilities for short term funding needs instead of the commercial paper program. Credit facility borrowings are based on a more stable base rate and the credit spread is fixed.

Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also enter into swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.

60

Item 4.     Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2022, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended March 31, 2022 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2022, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have been no changes in PSE’s internal control over financial reporting during the quarter ended March 31, 2022 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

61

PART II            OTHER INFORMATION

Item 1.         Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of March 31, 2022.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements in Item I of this report.

Given the size of the Company's operations, we have elected to adopt a threshold of $1.0 million in expected sanctions related to required disclosures of environmental proceedings to which the government is a party. As of the date of this filing, we are not aware of any matters that exceed this threshold and meet the definition for disclosure.

Item 1A.     Risk Factors

There have been no material changes from the risk factors set forth in Part 1, Item 1A, "Risk Factors" of the Company's Annual Report on Form 10-K for the year ended December 31, 2021. Although the Company has not been materially affected, the following represents an ongoing risk that the Company continues to monitor.

PSE could be adversely affected by disruptions in the global economy and rising geopolitical tensions caused by the ongoing military conflict between Russia and Ukraine. The global economy has been negatively impacted by the military conflict between Russia and Ukraine. Governments including the U.S., United Kingdom, and European Union imposed import and export controls on certain products and economic sanctions on certain industries and parties in Russia. Further escalation of geopolitical tensions related to the military conflict, including increased trade barriers or restrictions on global trade, could result in, among other things, cyberattacks, supply chain disruptions, and increased costs, including energy costs, which may adversely affect our business and supply chain. In addition, the effects of the ongoing conflict could heighten many of our known risks described in Part I, Item 1A, "Risk Factors" in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.

Item 6.         Exhibits

Included in the Exhibit Index are a list of exhibits filed as part of this Quarterly Report on Form 10-Q.

62

EXHIBIT INDEX

3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy, Inc. (Incorporated herein by reference to Exhibit 3.3 to Puget Energy's Current Report on Form 10-K, dated February 25, 2022, Commission File No. 001-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. (Incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy's Current Report on Form 10-K dated February 25, 2022, Commission File No. 001-04393).
4.1	Seventh Supplemental Indenture dated March 17, 2022 relating to Puget Energy's 4.224% Senior Secured Notes due 2032 (incorporated herein by reference to Exhibit 4.1 Puget Energy's Current Report on Form 8-K, filed March 18 2022, Commission File No. 1-1605.)
31.1*	Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*	Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*	Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended March 31, 2022 filed on May 4, 2022 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
104	Cover Page Interactive Data File (embedded within the inline XBRL document).

__________________

* Filed herewith.

63

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		PUGET ENERGY, INC. PUGET SOUND ENERGY, INC.
		/s/ Stephen King
		Stephen King Controller & Principal Accounting Officer
Date:	May 4, 2022

64

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Mary E. Kipp, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2022
/s/ Mary E. Kipp
Mary E. Kipp
President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kazi Hasan, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2022
/s/ Kazi Hasan
Kazi Hasan
Senior Vice President and
Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Mary E. Kipp, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2022
/s/ Mary E. Kipp
Mary E. Kipp
President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kazi Hasan, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s Board of Directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2022
/s/ Kazi Hasan
Kazi Hasan
Senior Vice President and
Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period ended March 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Mary E. Kipp, the President and Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	May 4, 2022
/s/ Mary E. Kipp
Mary E. Kipp
President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period ended March 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Kazi Hasan, Senior Vice President and Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	May 4, 2022
/s/ Kazi Hasan
Kazi Hasan
Senior Vice President and Chief Financial Officer

XML

Cover	3 Months Ended
	Mar. 31, 2022 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	1-16305
Entity Tax Identification Number	91-1969407
Entity Incorporation, State or Country Code	WA
Entity Address, Address Line One	355 110th Ave NE
Entity Address, City or Town	Bellevue
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98004
City Area Code	(425)
Local Phone Number	454-6363
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Shell Company	false
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2022
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Registrant Name	PUGET ENERGY INC /WA
Subsidiaries [Member]
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	1-4393
Entity Tax Identification Number	91-0374630
Entity Incorporation, State or Country Code	WA
Entity Address, Address Line One	355 110th Ave NE
Entity Address, City or Town	Bellevue
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98004
City Area Code	(425)
Local Phone Number	454-6363
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Shell Company	false
Document Fiscal Period Focus	Q1
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--03-31
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2022
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Registrant Name	PUGET SOUND ENERGY, INC.

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Operating revenue:
Electric	$ 756,377	$ 758,592
Natural gas	426,348	392,906
Other	10,712	8,588
Total operating revenue	1,193,437	1,160,086
Energy costs:
Purchased electricity	238,203	205,410
Electric generation fuel	60,644	60,418
Residential exchange	(23,070)	(25,802)
Purchased natural gas	177,333	155,015
Unrealized (gain) loss on derivative instruments, net	(131,921)	(23,002)
Utility operations and maintenance	170,300	160,540
Non-utility expense and other	15,419	9,906
Depreciation & amortization	164,576	208,431
Conservation amortization	30,141	34,060
Taxes other than income taxes	121,377	110,310
Total operating expenses	823,002	895,286
Operating income (loss)	370,435	264,800
Other income (expense):
Other income	13,164	13,630
Other expense	(3,154)	(1,510)
Interest charges:
AFUDC	4,129	3,586
Interest expense	(86,468)	(89,360)
Income (loss) before income taxes	298,106	191,146
Income tax (benefit) expense	19,811	2,153
Net income (loss)	278,295	188,993
Subsidiaries [Member]
Operating revenue:
Electric	756,377	758,592
Natural gas	426,348	392,906
Other	10,677	8,588
Total operating revenue	1,193,402	1,160,086
Energy costs:
Purchased electricity	238,203	205,410
Electric generation fuel	60,644	60,418
Residential exchange	(23,070)	(25,802)
Purchased natural gas	177,333	155,015
Unrealized (gain) loss on derivative instruments, net	(131,921)	(23,002)
Utility operations and maintenance	170,300	160,540
Non-utility expense and other	12,814	9,418
Depreciation & amortization	163,704	208,362
Conservation amortization	30,141	34,060
Taxes other than income taxes	121,116	110,310
Total operating expenses	819,264	894,729
Operating income (loss)	374,138	265,357
Other income (expense):
Other income	10,968	11,034
Other expense	(3,154)	(1,510)
Interest charges:
AFUDC	4,129	3,586
Interest expense	(63,144)	(62,371)
Income (loss) before income taxes	322,937	216,096
Income tax (benefit) expense	34,856	16,626
Net income (loss)	$ 288,081	$ 199,470

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Net Income (Loss) Attributable to Parent	$ 278,295	$ 188,993
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,831	2,385
Other comprehensive income (loss)	1,831	2,385
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total	280,126	191,378
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	288,081	199,470
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	3,588	4,458
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	97	96
Other comprehensive income (loss)	3,685	4,554
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total	$ 291,766	$ 204,024

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 487	$ 634
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	953	1,185
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 26

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Utility Plant [Abstract]
Public Utilities Property Plant And Equipment Electric Plant	$ 9,843,756	$ 9,729,643
Public Utilities Property Plant And Equipment Gas Plant	4,553,903	4,498,198
Public Utilities Property Plant And Equipment Common Plant	1,120,192	1,155,567
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(4,081,891)	(4,031,458)
Public Utilities, Property, Plant and Equipment, Net, Total	11,435,960	11,351,950
Other Property And Investments [Abstract]
Goodwill	1,656,513	1,656,513
Other Property And Investments	326,229	324,897
Total Other Property And Investments	1,982,742	1,981,410
Assets, Current [Abstract]
Cash and Cash Equivalents, at Carrying Value	603,757	56,946
Restricted Cash and Cash Equivalents, Current	30,525	46,204
Accounts Receivable, after Allowance for Credit Loss, Current	419,355	398,895
Unbilled Revenues	215,299	271,606
Other Inventory, Supplies, Gross	120,364	113,287
Fuel And Gas Inventory At Average Cost	47,360	59,393
Derivative Asset, Current	293,884	128,210
Prepaid Expense and Other Assets, Current	50,906	46,293
Power Contract Acquisition Adjustment Gain Current	16,303	17,274
Assets, Current, Total	1,797,753	1,138,108
Other Longterm And Regulatory Assets [Abstract]
Power Cost Adjustment Mechanism Asset, Noncurrent	67,808	79,546
purchase gas adjustment, long-term	44,020	57,935
Regulatory Assets Related To Power Contracts	9,362	9,689
Other Regulatory Assets	809,414	815,058
Derivative Asset, Noncurrent	36,690	26,197
Power Contract Acquisition Adjustment Non Current	59,332	63,660
Operating Lease, Right-of-Use Asset	182,077	184,957
Other Assets, Noncurrent	165,440	163,374
Total Longterm And Regulatory Assets	1,374,143	1,400,416
Assets, Total	16,590,598	15,871,884
Capitalization [Abstract]
Common stock	0	0
Additional Paid in Capital	3,523,532	3,523,532
Retained Earnings (Accumulated Deficit)	1,344,572	1,067,216
Accumulated Other Comprehensive Income (Loss), Net of Tax	(25,601)	(27,432)
Stockholders' Equity Attributable to Parent, Total	4,842,503	4,563,316
Long-term Debt, Excluding Current Maturities [Abstract]
Senior Notes, Noncurrent	4,662,000	4,662,000
Long-term Pollution Control Bond	161,860	161,860
Other Long-term Debt, Noncurrent	2,034,300	1,583,300
Debt discount and other	(203,217)	(203,394)
Long-term Debt, Excluding Current Maturities, Total	6,654,943	6,203,766
Capitalization, Long-term Debt and Equity, Total	11,497,446	10,767,082
Liabilities, Current [Abstract]
Accounts Payable, Current	376,793	444,384
Short-term Debt	69,750	140,000
Long-term Debt, Current Maturities	450,000	450,000
Accrued Expenses [Abstract]
Taxes Payable, Current	169,124	127,398
Employee-related Liabilities, Current	43,489	47,936
Interest Payable, Current	81,556	67,807
Derivative Liability, Current	40,237	63,309
Power Contract Acquisition Adjustment Loss Current	1,741	1,785
Operating Lease, Liability, Current	20,624	20,398
Other Liabilities, Current	87,814	62,406
Liabilities, Current, Total	1,341,128	1,425,423
Longterm And Regulatory Liabilities [Abstract]
Deferred Tax and Other Liabilities, Noncurrent	923,026	912,484
Derivative Liability, Noncurrent	22,373	40,965
Regulatory Liabilities, Noncurrent	930,374	844,184
Deferred Tax Liabilities, Regulatory Assets and Liabilities	852,280	865,976
Regulatory Liabilities Related To Power Contracts	75,635	80,934
Power Contract Acquisition Adjustment Loss Non Current	7,621	7,904
Operating Lease, Liability, Noncurrent	168,637	172,510
Finance Lease, Liability, Noncurrent	104,539	105,303
Other Deferred Credits	667,539	649,119
Total Longterm And Regulatory Liabilities	3,752,024	3,679,379
Commitments and Contingencies
Liabilities and Equity, Total	16,590,598	15,871,884
Subsidiaries [Member]
Utility Plant [Abstract]
Public Utilities Property Plant And Equipment Electric Plant	11,633,462	11,535,976
Public Utilities Property Plant And Equipment Gas Plant	5,109,791	5,054,622
Public Utilities Property Plant And Equipment Common Plant	1,142,049	1,177,598
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(6,449,342)	(6,416,246)
Public Utilities, Property, Plant and Equipment, Net, Total	11,435,960	11,351,950
Other Property And Investments [Abstract]
Other Property And Investments	76,507	74,602
Total Other Property And Investments	76,507	74,602
Assets, Current [Abstract]
Cash and Cash Equivalents, at Carrying Value	150,893	50,043
Restricted Cash and Cash Equivalents, Current	30,525	46,204
Accounts Receivable, after Allowance for Credit Loss, Current	420,726	402,602
Unbilled Revenues	215,299	271,606
Other Inventory, Supplies, Gross	120,364	113,287
Fuel And Gas Inventory At Average Cost	45,795	58,129
Derivative Asset, Current	293,884	128,210
Prepaid Expense and Other Assets, Current	50,906	46,293
Assets, Current, Total	1,328,392	1,116,374
Other Longterm And Regulatory Assets [Abstract]
Power Cost Adjustment Mechanism Asset, Noncurrent	67,808	79,546
purchase gas adjustment, long-term	44,020	57,935
Other Regulatory Assets	809,414	815,058
Derivative Asset, Noncurrent	36,690	26,197
Operating Lease, Right-of-Use Asset	182,077	184,957
Other Assets, Noncurrent	164,477	162,391
Total Longterm And Regulatory Assets	1,304,486	1,326,084
Assets, Total	14,145,345	13,869,010
Capitalization [Abstract]
Common stock	859	859
Additional Paid in Capital	3,485,105	3,485,105
Retained Earnings (Accumulated Deficit)	1,256,792	982,607
Accumulated Other Comprehensive Income (Loss), Net of Tax	(109,456)	(113,141)
Stockholders' Equity Attributable to Parent, Total	4,633,300	4,355,430
Long-term Debt, Excluding Current Maturities [Abstract]
Senior Notes, Noncurrent	4,662,000	4,662,000
Long-term Pollution Control Bond	161,860	161,860
Debt discount and other	(38,629)	(39,141)
Long-term Debt, Excluding Current Maturities, Total	4,785,231	4,784,719
Capitalization, Long-term Debt and Equity, Total	9,418,531	9,140,149
Liabilities, Current [Abstract]
Accounts Payable, Current	379,918	451,716
Short-term Debt	69,750	140,000
Accrued Expenses [Abstract]
Taxes Payable, Current	180,568	133,406
Employee-related Liabilities, Current	43,489	47,936
Interest Payable, Current	58,264	51,832
Derivative Liability, Current	40,237	63,309
Operating Lease, Liability, Current	20,624	20,398
Other Liabilities, Current	87,814	62,406
Liabilities, Current, Total	880,664	971,003
Longterm And Regulatory Liabilities [Abstract]
Deferred Tax and Other Liabilities, Noncurrent	1,104,851	1,084,203
Derivative Liability, Noncurrent	22,373	40,965
Regulatory Liabilities, Noncurrent	929,110	842,920
Deferred Tax Liabilities, Regulatory Assets and Liabilities	852,842	866,541
Operating Lease, Liability, Noncurrent	168,637	172,510
Finance Lease, Liability, Noncurrent	104,539	105,303
Other Deferred Credits	663,798	645,416
Total Longterm And Regulatory Liabilities	3,846,150	3,757,858
Commitments and Contingencies
Liabilities and Equity, Total	$ 14,145,345	$ 13,869,010

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
ASSETS
Construction work in progress	$ 696,617	$ 870,204
Assets, Current [Abstract]
Allowance for doubtful accounts	41,233	34,958
Common shareholder’s equity:
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	696,617	870,204
Allowance for doubtful accounts	$ 41,233	$ 34,958
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 696,617	$ 870,204
Assets, Current [Abstract]
Allowance for doubtful accounts	41,233	34,958
Common shareholder’s equity:
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	696,617	870,204
Allowance for doubtful accounts	$ 41,233	$ 34,958
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common Stock, Shares, Outstanding	85,903,791	85,903,791

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Subsidiaries [Member]	Subsidiaries [Member] Common Stock [Member]	Subsidiaries [Member] Additional Paid-in Capital [Member]	Subsidiaries [Member] Retained Earnings [Member]	Subsidiaries [Member] AOCI Attributable to Parent [Member]
Beginning Balance (in shares) at Dec. 31, 2020		200					85,903,791
Beginning Balance at Dec. 31, 2020	$ 4,139,882	$ 0	$ 3,313,532	$ 912,787	$ (86,437)	$ 4,181,409	$ 859	$ 3,485,105	$ 876,401	$ (180,956)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss) Attributable to Parent	188,993			188,993		199,470			199,470
Dividends, Common Stock	(22,939)			(22,939)		(52,053)			(52,053)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	2,385				2,385	4,554				4,554
Ending Balance (in shares) at Mar. 31, 2021		200					85,903,791
Ending Balance at Mar. 31, 2021	$ 4,308,321	$ 0	3,313,532	1,078,841	(84,052)	$ 4,333,380	$ 859	3,485,105	1,023,818	(176,402)
Beginning Balance (in shares) at Dec. 31, 2021	200	200				85,903,791	85,903,791
Beginning Balance at Dec. 31, 2021	$ 4,563,316	$ 0	3,523,532	1,067,216	(27,432)	$ 4,355,430	$ 859	3,485,105	982,607	(113,141)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss) Attributable to Parent	278,295			278,295		288,081			288,081
Dividends, Common Stock	(939)			(939)		(13,896)			(13,896)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	$ 1,831				1,831	$ 3,685				3,685
Ending Balance (in shares) at Mar. 31, 2022	200	200				85,903,791	85,903,791
Ending Balance at Mar. 31, 2022	$ 4,842,503	$ 0	$ 3,523,532	$ 1,344,572	$ (25,601)	$ 4,633,300	$ 859	$ 3,485,105	$ 1,256,792	$ (109,456)

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	$ 278,295	$ 188,993
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation & amortization	164,576	208,431
Conservation amortization	30,141	34,060
Deferred Income Taxes and Tax Credits	(3,641)	6,622
Unrealized Gain (Loss) on Derivatives	(131,921)	(23,002)
Afudc Equity	(6,971)	(5,780)
Monetized production tax credits	0	(45,178)
Other Noncash Income (Expense)	2,326	3,518
Increase (Decrease) in Other Regulatory Assets	4,470	(14,351)
Purchased gas adjustment	13,915	40,868
Increase (Decrease) in Other Operating Assets	(7,891)	(5,695)
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Accounts and Other Receivables	35,847	(19,743)
Increase (Decrease) in Materials and Supplies	(7,077)	442
Increase (Decrease) in Fuel Inventories	12,033	10,052
Increase (Decrease) in Prepaid Expense and Other Assets	(4,733)	(3,884)
Increase (Decrease) in Accounts Payable	(57,324)	(14,868)
Increase (Decrease) in Income Taxes Payable	41,726	23,476
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	18,615	(512)
Net Cash Provided by (Used in) Operating Activities, Total	382,386	383,449
Net Cash Provided by (Used in) Investing Activities [Abstract]
Construction expenditures excluding equity allowance for funds used during construction	(233,131)	(213,781)
Payments for (Proceeds from) Other Investing Activities	(532)	362
Net Cash Provided by (Used in) Investing Activities, Total	(233,663)	(213,419)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from (Repayments of) Short-term Debt	(70,250)	(182,800)
Payments of Dividends	(939)	(22,939)
Proceeds from Issuance of Long-term Debt	448,075	8,800
Repayments of Long-term Debt	0	(66)
Proceeds from (Payments for) Other Financing Activities	5,523	6,074
Net Cash Provided by (Used in) Financing Activities, Total	382,409	(190,931)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	531,132	(20,901)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	103,150	81,851	$ 81,851
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	634,282	60,950	103,150
Supplemental Cash Flow Information [Abstract]
Interest Paid, Excluding Capitalized Interest, Operating Activities	65,238	77,160
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Capital Expenditures Incurred but Not yet Paid	61,133	54,805
Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	288,081	199,470
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation & amortization	163,704	208,362
Conservation amortization	30,141	34,060
Deferred Income Taxes and Tax Credits	5,970	21,044
Unrealized Gain (Loss) on Derivatives	(131,921)	(23,002)
Afudc Equity	(6,971)	(5,780)
Monetized production tax credits	0	(45,178)
Other Noncash Income (Expense)	(328)	885
Increase (Decrease) in Other Regulatory Assets	4,470	(14,351)
Purchased gas adjustment	13,915	40,868
Increase (Decrease) in Other Operating Assets	(5,558)	(3,077)
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Accounts and Other Receivables	38,183	(17,957)
Increase (Decrease) in Materials and Supplies	(7,077)	442
Increase (Decrease) in Fuel Inventories	12,334	10,052
Increase (Decrease) in Prepaid Expense and Other Assets	(4,733)	(3,884)
Increase (Decrease) in Accounts Payable	(61,531)	(14,853)
Increase (Decrease) in Income Taxes Payable	47,162	23,527
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	11,300	3,549
Net Cash Provided by (Used in) Operating Activities, Total	397,141	414,177
Net Cash Provided by (Used in) Investing Activities [Abstract]
Construction expenditures excluding equity allowance for funds used during construction	(232,868)	(205,927)
Payments for (Proceeds from) Other Investing Activities	(532)	362
Net Cash Provided by (Used in) Investing Activities, Total	(233,400)	(205,565)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from (Repayments of) Short-term Debt	(70,250)	(182,800)
Payments of Dividends	(13,896)	(52,053)
Repayments of Long-term Debt	0	(66)
Proceeds from (Payments for) Other Financing Activities	5,576	6,080
Net Cash Provided by (Used in) Financing Activities, Total	(78,570)	(228,839)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	85,171	(20,227)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	96,247	80,721	80,721
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	181,418	60,494	$ 96,247
Supplemental Cash Flow Information [Abstract]
Interest Paid, Excluding Capitalized Interest, Operating Activities	51,357	47,749
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 61,133	$ 54,805

XML

Summary of Consolidation and Significant Accounting Policy

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Significant Accounting Policies

Summary of Consolidation and Significant Accounting Policy

Basis of Presentation

Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Allowance for Credit Losses

Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, natural gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.

The allowance increased during both periods due to both an increase in the provision combined with a reduction in receivables charged-off during the period. The Ratepayer Assistance and Preservation of Essential Services proclamation issued by the Washington State governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment. This moratorium ended on September 30, 2021, however, customer disconnects are only performed with approval from the WUTC.

The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2022 and 2021:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021
Allowance for credit losses:
Beginning balance	$	34,958	$	20,080
Provision for credit loss expense 1	9,767		12,452
Receivables charged-off	(3,492)		(2,140)
Total ending allowance balance	$	41,233	$	30,392

_______________

1 $4.7 million and $0.0 million of provision were deferred as cost specific to COVID-19 for the three months ended March 31, 2022 and 2021, respectively.

Tacoma LNG Facility

On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and provide LNG as fuel to transportation customers, particularly in the marine market at a lower cost due to the facility's scale.

Pursuant to an order by the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $244.8 million and $244.7 million of non-utility plant and construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" line item as of March 31, 2022 and December 31, 2021, respectively. Additionally, $2.2 million and $0.2 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for the three months ended March 31, 2022, and March 31, 2021, respectively. Further, $241.7 million and $239.6 million of natural gas plant and construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of March 31, 2022 and December 31, 2021, respectively, as PSE is a regulated entity.

Variable Interest Entities

On April 12, 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy certificates (RECs) to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Skookumchuck is a variable interest entity (VIE) and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $3.9 million and $5.7 million were recognized in purchased electricity on the Company's consolidated statements of income for the three months ended March 31, 2022 and March 31, 2021, respectively. Additionally, $2.7 million was included in accounts payable on the Company's balance sheet as of both March 31, 2022 and December 31, 2021.

On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE.

XML

New Accounting Pronouncements

3 Months Ended

Mar. 31, 2022

Accounting Standards Update and Change in Accounting Principle [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued Accounting Standards Update (ASU) 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020). ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of March 31, 2022, the Company has not utilized any of the expedients discussed within this ASU; however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.

XML

Revenue

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended March 31, 2022 and March 31, 2021:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2022
Revenue from contracts with customers:	Electric		Natural Gas		Other1		Total
Retail
Residential	$	416,260	$	292,596	$	—	$	708,856
Commercial	257,019		120,979		—		377,998
Industrial	30,073		8,085		—		38,158
Other	4,761		—		—		4,761
Wholesale	13,147		—		—		13,147
Transmission and transportation	11,222		5,446		—		16,668
Miscellaneous	1,150		309		10,712		12,171
Total revenue from contracts with customers	$	733,632	$	427,415	$	10,712	$	1,171,759
Total other revenue2	22,745		(1,067)		—		21,678
Total operating revenue	$	756,377	$	426,348	$	10,712	$	1,193,437

_____________

1 Other includes $0.1 million of Puget LNG revenues recorded at Puget Energy.

2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2021
Revenue from contracts with customers:	Electric		Natural Gas		Other		Total
Retail
Residential	$	401,510	$	276,687	$	—	$	678,197
Commercial	229,639		103,387		—		333,026
Industrial	27,533		7,535		—		35,068
Other	5,420		254		—		5,674
Wholesale	23,676		—		—		23,676
Transmission and transportation	9,226		5,161		—		14,387
Miscellaneous	8,401		1,077		8,588		18,066
Total revenue from contracts with customers	$	705,405	$	394,101	$	8,588	$	1,108,094
Total other revenue1	53,187		(1,195)		—		51,992
Total operating revenue	$	758,592	$	392,906	$	8,588	$	1,160,086

_____________

1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.

Transaction Price Allocated to Remaining Performance Obligations

In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:

Puget Energy
(Dollars in Thousands)	2024		2025		2026		2027		2028		Thereafter		Total
Remaining Performance Obligations	$	15,359	$	19,710	$	19,454	$	19,454	$	19,454	$	102,135	$	195,566

The Company has elected the optional exemption in ASC 606, under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. The primary sources of variability are (a) fluctuations in market index prices of natural gas used to determine aspects of variable pricing and (b) variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG or natural gas. As each unit of LNG or natural gas represents a separate performance obligation, future volumes are wholly unsatisfied.

XML

Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus, reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy, which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.

The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy
	March 31, 2022					December 31, 2021
(Dollars in Thousands)	Volumes (millions)	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	173,481	$	52,154	*	$	74,829	$	85,424
Natural gas derivatives (MMBtus)3	320	157,093		10,456		347	79,578		18,850
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274
Current		$	293,884	$	40,237		$	128,210	$	63,309
Long-term		36,690		22,373			26,197		40,965
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274

_______________

1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.

2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

* Electric portfolio derivatives consist of electric generation fuel of 231.2 million British Thermal Units (MMBtu) and purchased electricity of

6.0 million Megawatt Hours (MWhs) at March 31, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report.

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
	At March 31, 2022
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	330,574	$	—	$	330,574	$	(31,515)	$	—	$	299,059
Liabilities:
Energy derivative contracts	$	62,610	$	—	$	62,610	$	(31,515)	$	—	$	31,095

Puget Energy and Puget Sound Energy	At December 31, 2021
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	154,407	$	—	$	154,407	$	(40,833)	$	—	$	113,574
Liabilities:
Energy derivative contracts	$	104,274	$	—	$	104,274	$	(40,833)	$	(1,743)	$	61,698

_______________

1 All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.    

The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy and Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Classification	2022		2021
Gas for power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	86,873	$	1,628
Realized	Electric generation fuel	27,091		8,313
Power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	45,048		21,374
Realized	Purchased electricity	2,591		(13,303)
Total gain (loss) recognized in income on derivatives		$	161,603	$	18,012

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation.

The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of March 31, 2022, approximately 99.4% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.6% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE natural gas exchange (NGX) platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2022, PSE had cash posted as collateral of $6.1 million related to contracts executed on the ICE platform. Also, as of March 31, 2022, PSE had $17.0 million in cash posted as collateral and no letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended March 31, 2022.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At March 31, 2022						At December 31, 2021
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	23,484	$	—	$	23,484	$	52,537	$	—	$	52,537
Requested credit for adequate assurance	7,024		—		—		9,380		—		—
Forward value of contract3	—		—		N/A		1,743		12,782		N/A
Total	$	30,508	$	—	$	23,484	$	63,660	$	12,782	$	52,537

_______________

1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts

payable and accounts receivable.

2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to

demand collateral.

3 Collateral requirements may vary based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy 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. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department, which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.

The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes or that are transacted at illiquid delivery

locations are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $53.4 million and $53.2 million at March 31, 2022 and December 31, 2021 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,620,643	$	7,338,267	$	6,170,466	$	7,769,896
Long-term debt (variable-rate)	2	34,300		34,300		33,300		33,300
Total liabilities		$	6,654,943	$	7,372,567	$	6,203,766	$	7,803,196

Puget Sound Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639
Total liabilities		$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639

_______________

1 The carrying value includes debt issuances costs of $22.1 million and $22.7 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.5 million and $22.8 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:

Puget Energy and Puget Sound Energy	Fair Value At March 31, 2022						Fair Value At December 31, 2021
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	160,220	$	13,261	$	173,481	$	68,011	$	6,818	$	74,829
Natural gas derivative instruments	156,674		419		157,093		79,526		52		79,578
Total assets	$	316,894	$	13,680	$	330,574	$	147,537	$	6,870	$	154,407
Liabilities:
Electric derivative instruments	$	32,883	$	19,271	$	52,154	$	35,854	$	49,570	$	85,424
Natural gas derivative instruments	8,825		1,631		10,456		16,678		2,172		18,850
Total liabilities	$	41,708	$	20,902	$	62,610	$	52,532	$	51,742	$	104,274

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022						2021
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	38,820		—		38,820		820		—		820
Included in regulatory assets / liabilities	—		415		415		—		(888)		(888)
Settlements	(2,254)		324		(1,930)		1,728		189		1,917
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	176		169		345		—		—		—
Balance at end of period	$	(6,010)	$	(1,212)	$	(7,222)	$	(21,170)	$	(1,834)	$	(23,004)

_______________

1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $38.6 million and $0.8 million for three months ended March 31, 2022 and 2021, respectively.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.

The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and gas commodity contracts, respectively, as of the reporting date.

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2022:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	13,261	$	19,271	Discounted cash flow	Power prices (per MWh)	$	28.75	$	161.09	$	76.95
Natural gas	$	419	$	1,631	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.99	$	6.44	$	5.55

_______________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2021:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	6,818	$	49,570	Discounted cash flow	Power prices (per MWh)	$	21.88	$	119.38	$	61.51
Natural gas	$	52	$	2,172	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.65	$	7.54	$	5.89

___________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of March 31, 2022, and December 31, 2021, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $20.3 million and $17.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.

As of March 31, 2022, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and determined that no impairment was needed. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and liabilities were revalued in accordance with ASC 805, "Business Combinations."

XML

Retirement Benefits

3 Months Ended

Mar. 31, 2022

Subsidiaries [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new UA represented employees hired or rehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible pay each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Plan) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020.

Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income.

For further information, see Note 13, "Retirement Benefits" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2021.

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2022 and 2021:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(476)		72		87		6		2
Amortization of net loss (gain)	1,628		2,830		618		587		(4)		(10)
Net periodic benefit cost	$	1,735	$	2,562	$	1,142	$	1,082	$	39	$	19

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(378)		72		87		6		2
Amortization of net loss (gain)	3,806		5,311		663		635		(6)		(15)
Net periodic benefit cost	$	3,913	$	5,141	$	1,187	$	1,130	$	37	$	14

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2022 and December 31, 2021:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended		Year Ended		Three Months Ended		Year Ended		Three Months Ended		Year Ended
(Dollars in Thousands)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Change in benefit obligation:
Benefit obligation at beginning of period	$	834,960	$	849,383	$	43,155	$	46,742	$	11,654	$	12,114
Amendments	—		—		—		—		—		205
Service cost	6,797		26,888		139		456		55		155
Interest cost	6,087		22,381		313		1,183		81		302
Actuarial loss (gain)	—		(6,826)		—		828		—		(514)
Benefits paid	(11,723)		(55,831)		(494)		(6,054)		(227)		(803)
Medicare part D subsidy received	—		—		—		—		—		195
Administrative Expense	—		(1,035)		—		—		—		—
Benefit obligation at end of period	$	836,121	$	834,960	$	43,113	$	43,155	$	11,563	$	11,654

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2022, are expected to be at least $18.0 million, $2.8 million and $0.3 million, respectively. The Company contributed $0.5 million to fund the SERP during the three months ended March 31, 2022 and 2021. The Company contributed an immaterial amount to fund the other postretirement plans.

XML

Regulation and Rates

3 Months Ended

Mar. 31, 2022

Subsidiaries [Member]

Entity Information [Line Items]

Regulation and Rates Disclosure

Regulation and Rates

General Rate Case

PSE filed a general rate case (GRC) which includes a three year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by Revised Code of Washington (RCW) 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. The Washington Commission issued a procedural schedule and the case is pending. The Company cannot predict the outcome of the case at this time.

PSE filed a GRC with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.05%, and the natural gas increase to $1.3 million, or 0.15%, and became effective October 15, 2020 and October 1, 2020, respectively.

On July 30, 2021, the IRS issued a Private Letter Ruling (PLR) to PSE which concluded that in the 2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. The PLR required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. Accordingly, on September 28, 2021, the Washington Commission issued an order amending their order previously issued on July 8, 2020, to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed in the PLR. To reflect the impact of the PLR, PSE recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021. The annualized overall rate impact is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

Power Cost Only Rate Case

On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).

On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021.

Decoupling Filings

On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and fixed power cost sections originally filed through the annual May 2020 decoupling filing. The extension requires PSE to move amortization balances for electric decoupling as of August 31, 2020 to be collected from customers for a two-year period, instead of the originally approved one-year period. Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups.

On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On June 1, 2021, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.

On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.

On March 31, 2022, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2022 electric or natural gas decoupling revenue. At March 31, 2021, the analysis estimated $0.9 million of electric deferred revenue not to be collected within 24 months of the annual period in 2021; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. At March 31, 2021, natural gas deferred revenue was estimated to be collected within 24 months of the annual period in 2021; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue.

Power Cost Adjustment Mechanism

PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.

Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:

	Company’s Share				Customers' Share
Annual Power Cost Variability	Over		Under		Over		Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%	—	%
Over or Under Collected by between $17 million - $40 million	35		50		65		50
Over or Under Collected beyond $40 + million	10		10		90		90

For the three months ended March 31, 2022, in its PCA mechanism, PSE under recovered its allowable costs by $10.6 million of which zero was apportioned to customers and $0.3 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $11.4 million for the three months ended March 31, 2021, of which zero was apportioned to customers and accrued $0.3 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing

On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Microsoft Special Contracts, which will be included in allowed rates under the Decoupling Schedule 142 effective October 15, 2020.

PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021.

Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On April 30, 2022, PSE filed a 2021 PCA report with the Washington Commission that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.

Purchased Gas Adjustment Mechanism

On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. Those annual 2021 PGA rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.

The following table presents the PGA mechanism balances and activity at March 31, 2022 and December 31, 2021:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	161,647		364,775
Allowed PGA recovery	(175,930)		(396,236)
Interest	368		1,741
PGA receivable ending balance	$	44,020	$	57,935

Get to Zero Depreciation Deferral

On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get to Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. At March 31, 2022 and December 31, 2021, PSE deferred $7.9 million and $6.6 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89%. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's then-next GRC, which PSE filed on January 31, 2022, and is currently pending. Finally, the final order set the rate at which PSE could defer and recover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed CACAP-1 (dockets UE-200331 and UG-200332) with the Washington Commission revisions to its currently effective electric and natural gas service tariffs. The purpose of this filing was to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to September 30, 2020.

On March 28, 2021, the Washington Commission approved PSE’s CACAP-2 (dockets UE-210137 and UG-210138), effective April 12, 2021. With a program budget of $20.0 million for electric customers and $7.7 million for natural gas customers, CACAP-2 would provide up to $2,500 in bill assistance in arrearages per year for each qualifying low-income household. PSE stopped taking new applications for the COVID-19 Bill Assistance Program at 7:00 AM Pacific Standard Time on March 29, 2022. Estimates indicated that the electric funds would be exhausted once the current applications are completed.

On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (dockets UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program (HELP). With a combined total budget of $34.5 million for both electric and natural gas residential customers (capped at $23.7 million and $10.8 million, respectively). Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an opt-out option, in December 2021. Supplemental CACAP will be administered until funds are exhausted.

Storm Loss Deferral Mechanism

The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the three months ended March 31, 2022, PSE incurred $2.2 million in weather-related electric transmission and distribution system restoration costs, of which zero and $0.1 million was deferred as regulatory assets related to storms that occurred in 2022 and 2021, respectively. This compares to $23.3 million incurred in weather-related electric transmission and distribution system restoration costs for the three months ended March 31, 2021, of which the Company deferred $12.9 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the 2017 GRC settlement, to December 31, 2027, which was subsequently updated to December 31, 2025 as part of the 2019 GRC. The 2017 GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.

Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On May 19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a lawsuit against the Montana Attorney General challenging the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. As of March 31, 2022, the Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests.

Other Commitments and Contingencies

There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2021.

XML

Leases (Notes)	3 Months Ended
	Mar. 31, 2022
Leases [Abstract]
Leases	LeasesAs of March 31, 2022, there have been no material changes regarding the Company's leases. For further information, see Note 9, "Leases" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

XML

Other

3 Months Ended

Mar. 31, 2022

Other [Abstract]

Other

Other

Long-Term Debt

On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.

On June 23, 2021, Puget Energy received an equity contribution from Puget Equico, LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan.

On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes.

On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes were issued for a period of 10 years, mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance were used for repayment of Puget Energy notes that mature July 2022 and for general corporate purposes.

On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.

As of March 31, 2022, Puget Energy maintained an $800.0 million credit facility, of which $34.3 million was drawn and outstanding under the facility. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

Short-term Debt

Short-Term Debt

As of March 31, 2022, no amount was drawn under PSE's credit facility and $69.8 million was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2021.

XML

Summary of Consolidation and Significant Accounting Policy (Tables)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Accounts Receivable, Allowance for Credit Loss

The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2022 and 2021:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021
Allowance for credit losses:
Beginning balance	$	34,958	$	20,080
Provision for credit loss expense 1	9,767		12,452
Receivables charged-off	(3,492)		(2,140)
Total ending allowance balance	$	41,233	$	30,392

_______________

1 $4.7 million and $0.0 million of provision were deferred as cost specific to COVID-19 for the three months ended March 31, 2022 and 2021, respectively.

XML

Revenue (Tables)

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended March 31, 2022 and March 31, 2021:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2022
Revenue from contracts with customers:	Electric		Natural Gas		Other1		Total
Retail
Residential	$	416,260	$	292,596	$	—	$	708,856
Commercial	257,019		120,979		—		377,998
Industrial	30,073		8,085		—		38,158
Other	4,761		—		—		4,761
Wholesale	13,147		—		—		13,147
Transmission and transportation	11,222		5,446		—		16,668
Miscellaneous	1,150		309		10,712		12,171
Total revenue from contracts with customers	$	733,632	$	427,415	$	10,712	$	1,171,759
Total other revenue2	22,745		(1,067)		—		21,678
Total operating revenue	$	756,377	$	426,348	$	10,712	$	1,193,437

_____________

1 Other includes $0.1 million of Puget LNG revenues recorded at Puget Energy.

2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31, 2021
Revenue from contracts with customers:	Electric		Natural Gas		Other		Total
Retail
Residential	$	401,510	$	276,687	$	—	$	678,197
Commercial	229,639		103,387		—		333,026
Industrial	27,533		7,535		—		35,068
Other	5,420		254		—		5,674
Wholesale	23,676		—		—		23,676
Transmission and transportation	9,226		5,161		—		14,387
Miscellaneous	8,401		1,077		8,588		18,066
Total revenue from contracts with customers	$	705,405	$	394,101	$	8,588	$	1,108,094
Total other revenue1	53,187		(1,195)		—		51,992
Total operating revenue	$	758,592	$	392,906	$	8,588	$	1,160,086

_____________

1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:

Puget Energy
(Dollars in Thousands)	2024		2025		2026		2027		2028		Thereafter		Total
Remaining Performance Obligations	$	15,359	$	19,710	$	19,454	$	19,454	$	19,454	$	102,135	$	195,566

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2022

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:

Puget Energy and Puget Sound Energy
	March 31, 2022					December 31, 2021
(Dollars in Thousands)	Volumes (millions)	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	173,481	$	52,154	*	$	74,829	$	85,424
Natural gas derivatives (MMBtus)3	320	157,093		10,456		347	79,578		18,850
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274
Current		$	293,884	$	40,237		$	128,210	$	63,309
Long-term		36,690		22,373			26,197		40,965
Total derivative contracts		$	330,574	$	62,610		$	154,407	$	104,274

_______________

1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.

2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

* Electric portfolio derivatives consist of electric generation fuel of 231.2 million British Thermal Units (MMBtu) and purchased electricity of

6.0 million Megawatt Hours (MWhs) at March 31, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021.

Offsetting Assets and Liabilities

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
	At March 31, 2022
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	330,574	$	—	$	330,574	$	(31,515)	$	—	$	299,059
Liabilities:
Energy derivative contracts	$	62,610	$	—	$	62,610	$	(31,515)	$	—	$	31,095

Puget Energy and Puget Sound Energy	At December 31, 2021
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts		Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	154,407	$	—	$	154,407	$	(40,833)	$	—	$	113,574
Liabilities:
Energy derivative contracts	$	104,274	$	—	$	104,274	$	(40,833)	$	(1,743)	$	61,698

_______________

1 All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off.

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy and Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Classification	2022		2021
Gas for power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	86,873	$	1,628
Realized	Electric generation fuel	27,091		8,313
Power derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	45,048		21,374
Realized	Purchased electricity	2,591		(13,303)
Total gain (loss) recognized in income on derivatives		$	161,603	$	18,012

Schedule of Credit Risk Related Contingent Features

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At March 31, 2022						At December 31, 2021
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	23,484	$	—	$	23,484	$	52,537	$	—	$	52,537
Requested credit for adequate assurance	7,024		—		—		9,380		—		—
Forward value of contract3	—		—		N/A		1,743		12,782		N/A
Total	$	30,508	$	—	$	23,484	$	63,660	$	12,782	$	52,537

_______________

1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts

payable and accounts receivable.

2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to

demand collateral.

3 Collateral requirements may vary based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Inputs, Liabilities, Quantitative Information

The fair value of the long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,620,643	$	7,338,267	$	6,170,466	$	7,769,896
Long-term debt (variable-rate)	2	34,300		34,300		33,300		33,300
Total liabilities		$	6,654,943	$	7,372,567	$	6,203,766	$	7,803,196

Puget Sound Energy		March 31, 2022				December 31, 2021
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639
Total liabilities		$	4,785,231	$	5,382,446	$	4,784,719	$	6,145,639

_______________

1 The carrying value includes debt issuances costs of $22.1 million and $22.7 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.5 million and $22.8 million for March 31, 2022 and December 31, 2021, respectively, which are not included in fair value.

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:

Puget Energy and Puget Sound Energy	Fair Value At March 31, 2022						Fair Value At December 31, 2021
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	160,220	$	13,261	$	173,481	$	68,011	$	6,818	$	74,829
Natural gas derivative instruments	156,674		419		157,093		79,526		52		79,578
Total assets	$	316,894	$	13,680	$	330,574	$	147,537	$	6,870	$	154,407
Liabilities:
Electric derivative instruments	$	32,883	$	19,271	$	52,154	$	35,854	$	49,570	$	85,424
Natural gas derivative instruments	8,825		1,631		10,456		16,678		2,172		18,850
Total liabilities	$	41,708	$	20,902	$	62,610	$	52,532	$	51,742	$	104,274

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2022						2021
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(42,752)	$	(2,120)	$	(44,872)	$	(23,718)	$	(1,135)	$	(24,853)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	38,820		—		38,820		820		—		820
Included in regulatory assets / liabilities	—		415		415		—		(888)		(888)
Settlements	(2,254)		324		(1,930)		1,728		189		1,917
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	176		169		345		—		—		—
Balance at end of period	$	(6,010)	$	(1,212)	$	(7,222)	$	(21,170)	$	(1,834)	$	(23,004)

_______________

1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $38.6 million and $0.8 million for three months ended March 31, 2022 and 2021, respectively.

Fair Value Inputs, Assets and Liabilities, Quantitative Information

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2022:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	13,261	$	19,271	Discounted cash flow	Power prices (per MWh)	$	28.75	$	161.09	$	76.95
Natural gas	$	419	$	1,631	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.99	$	6.44	$	5.55

_______________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2021:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	6,818	$	49,570	Discounted cash flow	Power prices (per MWh)	$	21.88	$	119.38	$	61.51
Natural gas	$	52	$	2,172	Discounted cash flow	Natural gas prices (per MMBtu)	$	3.65	$	7.54	$	5.89

___________

1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

XML

Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2022

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2022 and 2021:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(476)		72		87		6		2
Amortization of net loss (gain)	1,628		2,830		618		587		(4)		(10)
Net periodic benefit cost	$	1,735	$	2,562	$	1,142	$	1,082	$	39	$	19

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2022		2021		2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	6,797	$	6,711	$	139	$	115	$	55	$	41
Interest cost	6,087		5,578		313		293		81		77
Expected return on plan assets	(12,777)		(12,081)		—		—		(99)		(91)
Amortization of prior service cost	—		(378)		72		87		6		2
Amortization of net loss (gain)	3,806		5,311		663		635		(6)		(15)
Net periodic benefit cost	$	3,913	$	5,141	$	1,187	$	1,130	$	37	$	14

Schedule of Changes in Projected Benefit Obligations

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2022 and December 31, 2021:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended		Year Ended		Three Months Ended		Year Ended		Three Months Ended		Year Ended
(Dollars in Thousands)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Change in benefit obligation:
Benefit obligation at beginning of period	$	834,960	$	849,383	$	43,155	$	46,742	$	11,654	$	12,114
Amendments	—		—		—		—		—		205
Service cost	6,797		26,888		139		456		55		155
Interest cost	6,087		22,381		313		1,183		81		302
Actuarial loss (gain)	—		(6,826)		—		828		—		(514)
Benefits paid	(11,723)		(55,831)		(494)		(6,054)		(227)		(803)
Medicare part D subsidy received	—		—		—		—		—		195
Administrative Expense	—		(1,035)		—		—		—		—
Benefit obligation at end of period	$	836,121	$	834,960	$	43,113	$	43,155	$	11,563	$	11,654

XML

Regulation and Rates Public Utilities, Regulatory Proceeding (Tables) - Subsidiaries [Member]

3 Months Ended

Mar. 31, 2022

Purchased Gas Adjustment [Member] | Natural Gas

Regulation and Rates [Line Items]

Schedule of PGA Receivable Payable

The following table presents the PGA mechanism balances and activity at March 31, 2022 and December 31, 2021:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2022		2021
PGA receivable beginning balance	$	57,935	$	87,655
Actual natural gas costs	161,647		364,775
Allowed PGA recovery	(175,930)		(396,236)
Interest	368		1,741
PGA receivable ending balance	$	44,020	$	57,935

PCA Mechanism [Member] | Electricity

Regulation and Rates [Line Items]

Schedule of Graduated Scale of Rate Adjustment Mechanism

Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:

	Company’s Share				Customers' Share
Annual Power Cost Variability	Over		Under		Over		Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%	—	%
Over or Under Collected by between $17 million - $40 million	35		50		65		50
Over or Under Collected beyond $40 + million	10		10		90		90

XML

Summary of Consolidation and Significant Accounting Policy - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) mi²	Mar. 31, 2021 USD ($)	Apr. 29, 2022 USD ($)	Dec. 31, 2021 USD ($)
Puget LNG [Member]
Summary of Consolidation Policy
Operating Costs and Expenses	$ 2.2	$ 0.2
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000
Contract Length, PPA	20 years
Variable Interest Entity, Measure of Activity, Expense	$ 3.9	$ 5.7
Variable Interest Entity, Payable	2.7			$ 2.7
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Construction in Progress, Gross				239.6
Public Utilities, Property, Plant and Equipment, Generation or Processing	$ 241.7
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%
Puget LNG [Member] | Natural Gas, US Regulated [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant, Ownership Amount of Other Assets	$ 244.8
Construction in Progress, Gross				$ 244.7
Variable Interest Entity, Not Primary Beneficiary | Skookumchuck Wind Energy Project
Summary of Consolidation Policy
Equity Method Investments	$ 0.0
Variable Interest Entity, Not Primary Beneficiary | Subsequent Event [Member] | Golden Hills Wind Farm
Summary of Consolidation Policy
Equity Method Investments			$ 0.0

XML

Summary of Consolidation and Significant Accounting Policy - Allowance for Credit Loss (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for Credit Losses, Beginning Balance			$ 34,958	$ 20,080
Provision for Credit Loss	$ 9,767	$ 12,452
Receivables Charged-Off	3,492	2,140
Allowance for Credit Loss, Ending Balance	41,233	30,392
Bad Debt Deferral, COVID 19	$ 4,700	$ 0

XML

Revenue (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Dec. 31, 2020	Mar. 31, 2022	Mar. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		$ 1,171,759	$ 1,108,094
Total Other Revenue		21,678	51,992
Revenues		1,193,437	1,160,086
Non-utility expense and other		15,419	9,906
Electric		756,377	758,592
Natural gas		426,348	392,906
Other		10,712	8,588
Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		708,856	678,197
Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		377,998	333,026
Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		38,158	35,068
Other Retail Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		4,761	5,674
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		13,147	23,676
Transmission and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		16,668	14,387
Miscellaneous Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		12,171	18,066
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		733,632	705,405
Total Other Revenue		22,745	53,187
Electricity, US Regulated [Member] | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		416,260	401,510
Electricity, US Regulated [Member] | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		257,019	229,639
Electricity, US Regulated [Member] | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		30,073	27,533
Electricity, US Regulated [Member] | Other Retail Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		4,761	5,420
Electricity, US Regulated [Member] | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		13,147	23,676
Electricity, US Regulated [Member] | Transmission and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		11,222	9,226
Electricity, US Regulated [Member] | Miscellaneous Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		1,150	8,401
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		427,415	394,101
Total Other Revenue		(1,067)	(1,195)
Natural Gas, US Regulated [Member] | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		292,596	276,687
Natural Gas, US Regulated [Member] | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		120,979	103,387
Natural Gas, US Regulated [Member] | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		8,085	7,535
Natural Gas, US Regulated [Member] | Other Retail Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	254
Natural Gas, US Regulated [Member] | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Natural Gas, US Regulated [Member] | Transmission and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		5,446	5,161
Natural Gas, US Regulated [Member] | Miscellaneous Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		309	1,077
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		10,712	8,588
Total Other Revenue		0	0
Other Revenue From Contracts with Customers [Member] | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Other Retail Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Transmission and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	0
Other Revenue From Contracts with Customers [Member] | Miscellaneous Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		10,712	8,588
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Revenues		1,193,402	1,160,086
Non-utility expense and other		12,814	9,418
Electric		756,377	758,592
Natural gas		426,348	392,906
Other		10,677	$ 8,588
Puget LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2026		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction		102,135
Revenue, Remaining Performance Obligation, Amount		195,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025		19,710
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025		15,359
Remaining Contract Term, PLNG	10 years
Puget LNG [Member] | Other Revenue From Contracts with Customers [Member] | Miscellaneous Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		$ 100

XML

Accounting for Derivative Instruments and Hedging Activities Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($)
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years
Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 17.0
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	99.40%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	0.60%
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 0.0

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions		Mar. 31, 2022 USD ($) MMBTU	Dec. 31, 2021 USD ($) MMBTU
Derivative [Line Items]
Current, Assets		$ 293,884	$ 128,210
Long-term, Assets		36,690	26,197
Current, Liabilities		40,237	63,309
Long-term, Liabilities		22,373	40,965
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current, Assets		293,884	128,210
Long-term, Assets		36,690	26,197
Assets	[1]	330,574	154,407
Current, Liabilities		40,237	63,309
Long-term, Liabilities		22,373	40,965
Derivative Liability	[2]	$ 62,610	$ 104,274
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		320.0	347.0
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets		$ 173,481	$ 74,829
Derivative Liability		52,154	85,424
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets		157,093	79,578
Derivative Liability		$ 10,456	$ 18,850
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		231.2	238.0
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		6.0	8.1

[1] _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.

[2] 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

XML

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Assets:
Gross Amount Recognized in the Statement of Financial Position	$ 330,574	$ 154,407
Gross Amounts Offset in the Statement of Financial Position	0	0
Assets	330,574	154,407
Commodity Contracts	(31,515)	(40,833)
Cash Collateral Received	0	0
Net Amount	299,059	113,574
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	62,610	104,274
Gross Amounts Offset in the Statement of Financial Position	0	0
Derivative Liability	62,610	104,274
Commodity Contracts	(31,515)	(40,833)
Cash Collateral Posted	0	(1,743)
Net Amount	$ 31,095	$ 61,698

XML

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 131,921	$ 23,002
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	161,603	18,012
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	86,873	1,628
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric Generation Fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	27,091	8,313
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	2,591	(13,303)
Not Designated as Hedging Instrument [Member] | Electricity, US Regulated [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 45,048	$ 21,374

XML

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ 30,508	$ 63,660
Posted Collateral	0	12,782
Additional Collateral, Aggregate Fair Value	23,484	52,537
Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	17,000
Electricity, US Regulated [Member]
Derivative [Line Items]
Posted Collateral	6,100
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	23,484	52,537
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	23,484	52,537
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	0
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	7,024	9,380
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	0	0
Forward Value of Contract [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	0	1,743
Posted Collateral	$ 0	$ 12,782

XML

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($)	Mar. 31, 2022	Dec. 31, 2021
Liabilities:
Total long-term debt	$ 6,654,943,000	$ 6,203,766,000
Carrying Value [Member] | Level 2 [Member]
Liabilities:
Notes Receivable, Fair Value Disclosure	53,400,000	53,200,000
Subsidiaries [Member]
Liabilities:
Total long-term debt	4,785,231,000	4,784,719,000
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	7,372,567,000	7,803,196,000
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	7,338,267,000	7,769,896,000
Long-term debt (variable-rate)	34,300,000	33,300,000
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,654,943,000	6,203,766,000
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	6,620,643,000	6,170,466,000
Long-term debt (variable-rate)	34,300,000	33,300,000
Debt issuance costs	22,100,000	22,700,000
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt	5,382,446,000	6,145,639,000
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	5,382,446,000	6,145,639,000
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt	4,785,231,000	4,784,719,000
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	4,785,231,000	4,784,719,000
Debt issuance costs	$ 22,500,000	$ 22,800,000

XML

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	$ (7,222)	$ (23,004)	$ (44,872)	$ (24,853)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	38,820	820
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	415	(888)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	(1,930)	1,917
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	345	0
Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(6,010)	(21,170)	(42,752)	(23,718)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	38,820	820
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	(2,254)	1,728
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	176	0
Gain (loss) on derivatives	38,600	800
Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(1,212)	(1,834)	(2,120)	$ (1,135)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	415	(888)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	324	189
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	169	$ 0
Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	330,574		154,407
Derivative Liability	62,610		104,274
Fair Value, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	173,481		74,829
Derivative Liability	52,154		85,424
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	157,093		79,578
Derivative Liability	10,456		18,850
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	316,894		147,537
Derivative Liability	41,708		52,532
Fair Value, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	160,220		68,011
Derivative Liability	32,883		35,854
Fair Value, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	156,674		79,526
Derivative Liability	8,825		16,678
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	13,680		6,870
Derivative Liability	20,902		51,742
Fair Value, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	13,261		6,818
Derivative Liability	19,271		49,570
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	419		52
Derivative Liability	$ 1,631		$ 2,172

XML

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($) $ / MWh $ / MMBTU	Dec. 31, 2021 USD ($) $ / MWh $ / MMBTU
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	0.10%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 20,300,000	$ 17,900,000
Impairment of Intangible Assets, Finite-lived	0
Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	330,574,000	154,407,000
Derivative Liability	62,610,000	104,274,000
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	13,680,000	6,870,000
Derivative Liability	$ 20,902,000	$ 51,742,000
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	28.75	21.88
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	161.09	119.38
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	76.95	61.51
Electric Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 173,481,000	$ 74,829,000
Derivative Liability	52,154,000	85,424,000
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	13,261,000	6,818,000
Derivative Liability	19,271,000	49,570,000
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Parent Company [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	13,261,000	6,818,000
Derivative Liability	$ 19,271,000	$ 49,570,000
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	3.99	3.65
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	6.44	7.54
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	5.55	5.89
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 157,093,000	$ 79,578,000
Derivative Liability	10,456,000	18,850,000
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	419,000	52,000
Derivative Liability	1,631,000	2,172,000
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | Parent Company [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	419,000	52,000
Derivative Liability	$ 1,631,000	$ 2,172,000

XML

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Qualified Pension Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	$ 6,797		$ 26,888
Defined Benefit Plan, Interest Cost	6,087		22,381
Qualified Pension Benefits [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	6,797	$ 6,711
Defined Benefit Plan, Interest Cost	6,087	5,578
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(12,777)	(12,081)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	(476)
Defined Benefit Plan, Amortization of Gain (Loss)	1,628	2,830
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	1,735	2,562
Qualified Pension Benefits [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	6,797	6,711
Defined Benefit Plan, Interest Cost	6,087	5,578
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(12,777)	(12,081)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	(378)
Defined Benefit Plan, Amortization of Gain (Loss)	3,806	5,311
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	3,913	5,141
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	139		456
Defined Benefit Plan, Interest Cost	313		1,183
Supplemental Employee Retirement Plan [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	139	115
Defined Benefit Plan, Interest Cost	313	293
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	72	87
Defined Benefit Plan, Amortization of Gain (Loss)	618	587
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	1,142	1,082
Supplemental Employee Retirement Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	139	115
Defined Benefit Plan, Interest Cost	313	293
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	72	87
Defined Benefit Plan, Amortization of Gain (Loss)	663	635
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	1,187	1,130
Other Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	55		155
Defined Benefit Plan, Interest Cost	81		$ 302
Other Benefit [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	55	41
Defined Benefit Plan, Interest Cost	81	77
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(99)	(91)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	6	2
Defined Benefit Plan, Amortization of Gain (Loss)	(4)	(10)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	39	19
Other Benefit [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	55	41
Defined Benefit Plan, Interest Cost	81	77
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(99)	(91)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	6	2
Defined Benefit Plan, Amortization of Gain (Loss)	(6)	(15)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	$ 37	$ 14

XML

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	$ 834,960	$ 849,383
Defined Benefit Plan, Service Cost	6,797	26,888
Defined Benefit Plan, Interest Cost	6,087	22,381
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	(6,826)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(11,723)	(55,831)
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt	0	0
defined benefit plan expected administration expense	0	1,035
Defined Benefit Plan, Benefit Obligation, Ending Balance	836,121	834,960
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	43,155	46,742
Defined Benefit Plan, Service Cost	139	456
Defined Benefit Plan, Interest Cost	313	1,183
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	828
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(494)	(6,054)
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt	0	0
defined benefit plan expected administration expense	0	0
Defined Benefit Plan, Benefit Obligation, Ending Balance	43,113	43,155
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	11,654	12,114
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	(205)
Defined Benefit Plan, Service Cost	55	155
Defined Benefit Plan, Interest Cost	81	302
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	(514)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(227)	(803)
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt	0	195
defined benefit plan expected administration expense	0	0
Defined Benefit Plan, Benefit Obligation, Ending Balance	11,563	11,654
Qualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Nonqualified Plan [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	$ 0	$ 0

XML

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2022
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Interest Credit	4.00%
UA represented [Member] | employer contribution [Member] | Subsidiaries [Member] | Collective Bargaining Arrangement [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%
IBEW represented | employer contribution [Member] | Subsidiaries [Member] | Collective Bargaining Arrangement [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	4.00%
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 0.5	$ 0.5
Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 18.0
Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			2.8
Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

XML

Regulation and Rates (Details) - USD ($)															3 Months Ended		6 Months Ended		12 Months Ended
	Nov. 15, 2021	Nov. 01, 2021	Oct. 01, 2021	Sep. 28, 2021	Jul. 01, 2021	Apr. 12, 2021	Mar. 02, 2021	Feb. 02, 2021	Dec. 09, 2020	Oct. 15, 2020	Oct. 01, 2020	Jul. 08, 2020	Jun. 20, 2019	Apr. 10, 2019	Mar. 31, 2022	Mar. 31, 2021	Jun. 30, 2021	Sep. 30, 2020	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2021	Dec. 31, 2020	Apr. 13, 2020	Jan. 01, 2018
Regulatory Assets [Line Items]
Income tax (benefit) expense															$ 19,811,000	$ 2,153,000
Depreciation & amortization															164,576,000	208,431,000
Other Regulatory Assets															809,414,000							$ 815,058,000
Revenues															1,193,437,000	1,160,086,000
purchase gas adjustment, long-term															44,020,000							57,935,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense															34,856,000	16,626,000
Annual Power Cost Variability, Interest															300,000	300,000
Depreciation & amortization															163,704,000	208,362,000
Liabilities, Other than Long-term Debt, Noncurrent	$ 34,500,000																							$ 11,000,000
Customer Bill Assistance	2,500					$ 2,500												$ 1,000
Other Regulatory Assets															809,414,000							815,058,000
Revenues															1,193,402,000	1,160,086,000
purchase gas adjustment, long-term															44,020,000							57,935,000	$ 87,655,000
Subsidiaries [Member] | Under-collection [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount															10,600,000	11,400,000						68,000,000	76,100,000
Subsidiaries [Member] | Under-collection [Member] | Companys share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount																						31,300,000	32,100,000
Subsidiaries [Member] | Under-collection [Member] | Customer's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount															0	0						36,700,000	44,000,000
Subsidiaries [Member] | Under-collection [Member] | Customer's share plus interest
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount																						38,400,000	46,000,000
Subsidiaries [Member] | Maximum Power | Customer's share plus interest
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount																						20,000,000	$ 20,000,000
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period															2,200,000	23,300,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold																									$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs																									$ 500,000
Subsidiaries [Member] | Electricity
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	23,700,000					20,000,000
Subsidiaries [Member] | Natural Gas
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	$ 10,800,000					$ 7,700,000
General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 18,900,000
Regulatory assets and additional revenues																						24,500,000
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage													6.90%
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 15,800,000	$ 48,300,000						$ 900,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 77,100,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage				3.70%
Public Utilities, Approved Rate Increase (Decrease), Percentage			0.70%	2.30%						0.05%
Public Utilities, Approved Debt Capital Structure, Percentage												7.39%
Public Utilities, Interim Rate Increase (Decrease), Amount				$ 59,600,000								$ 29,500,000
Public Utilities, Interim Rate Increase (Decrease), Percentage												1.60%
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount				17,500,000
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage													7.90%
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 3,100,000	4,900,000							$ 1,300,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 45,300,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage				5.90%
Public Utilities, Approved Rate Increase (Decrease), Percentage			0.30%	0.60%							0.15%
Public Utilities, Interim Rate Increase (Decrease), Amount				$ 42,900,000								$ 36,500,000
Public Utilities, Interim Rate Increase (Decrease), Percentage												4.00%
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount				$ 2,400,000
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage												6.80%
Public Utilities, Approved Equity Capital Structure, Percentage												48.50%
Public Utilities, Approved Return on Equity, Percentage												9.40%
Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Deferred Revenue, Revenue Recognized																0
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized															0	900,000
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized															0
Purchased Gas Adjustment [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 59,100,000
Purchased natural gas costs															161,647,000		$ 364,775,000
Purchased natural gas costs, recoverable															(175,930,000)		(396,236,000)
Purchased natural gas adjustment, interest															368,000		$ 1,741,000
Out of Cycle PGA		69,400,000
Get to Zero Deferral Filing [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities														6.89%
Depreciation & amortization															7,900,000							$ 6,600,000
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life														10 years
Power Cost Only Rate Case | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage							3.10%	4.10%	3.70%
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 65,300,000	$ 88,000,000	$ 78,500,000
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 70,900,000
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.30%
Purchased Gas Adjustment, Schedule 101 | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		80,600,000
purchased gas adjustment, Schedule 106 106B | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (21,500,000)
storm that occurred in 2020 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period																200,000
Storm that occurred in 2021 | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period															100,000	$ 12,900,000
Storm that occurred in 2022 | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period															$ 0
Forecast [Member] | General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities																			7.49%	7.44%	7.39%
Public Utilities, Requested Return on Equity, Percentage																			9.90%	9.90%	9.90%
Forecast [Member] | General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage																			1.20%	2.50%	13.60%
Forecast [Member] | General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage																			1.80%	2.30%	13.00%

XML

Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2022 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Interest	$ 0.3	$ 0.3
Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount	10.6	11.4	$ 68.0	$ 76.1
Under-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount			31.3	32.1
Under-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount	$ 0.0	$ 0.0	36.7	44.0
Under-collection [Member] | Customer's share plus interest
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount			38.4	46.0
Maximum Power | Customer's share plus interest
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount			$ 20.0	$ 20.0
Range 1 [Member] | Over-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	1
Range 1 [Member] | Over-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0
Range 1 [Member] | Under-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	1
Range 1 [Member] | Under-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0
Range 2 [Member] | Over-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.35
Range 2 [Member] | Over-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.65
Range 2 [Member] | Under-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.50
Range 2 [Member] | Under-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.50
Range 3 [Member] | Over-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.10
Range 3 [Member] | Over-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.90
Range 3 [Member] | Under-collection [Member] | Companys share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.10
Range 3 [Member] | Under-collection [Member] | Customer's share [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability	0.90

XML

Commitments and Contingencies (Details)	Mar. 31, 2022
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%

XML

Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Lessee, Operating Lease, Description [Abstract]
Operating Lease, Right-of-Use Asset	$ 182,077	$ 184,957
Operating Lease, Liability, Current	20,624	20,398
Operating Lease, Liability, Noncurrent	$ 168,637	$ 172,510

XML

Other - Narrative (Details) - USD ($)		3 Months Ended		4 Months Ended
	Apr. 28, 2022	Mar. 31, 2022	Mar. 31, 2021	Apr. 28, 2022	Mar. 17, 2022	Dec. 31, 2021	Sep. 15, 2021	Jun. 14, 2021
Debt Instrument [Line Items]
Long-term Debt, Current Maturities		$ 450,000,000				$ 450,000,000
Repayments of Long-term Debt		0	$ 66,000
Line of Credit Facility, Maximum Borrowing Capacity		800,000,000
Line of Credit Facility, Maximum Amount Outstanding During Period		34,300,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		0	$ 66,000
Commercial Paper		69,800,000
2.379% Senior Secured Note Due 2028 [Member] | Senior Secured Note
Debt Instrument [Line Items]
Long-term Debt, Gross								$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage								2.379%
Long-term Debt, Term								7 years
6.000% Senior Secured Note Due 2021 | Senior Secured Note
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage								6.00%
Long-term Debt, Current Maturities								$ 500,000,000
$210M Term Loan Due 2022
Debt Instrument [Line Items]
Repayments of Long-term Debt		210,000,000
Working Capital Needs [Member] | Subsidiaries [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Amount Outstanding During Period		$ 0
2.893% Senior Secured Note Due 2051 | Senior Secured Note | Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross							$ 450,000,000
Debt Instrument, Interest Rate, Stated Percentage							2.893%
Long-term Debt, Term							30 years
4.224% Senior Secured Note Due 2032 | Senior Secured Note
Debt Instrument [Line Items]
Long-term Debt, Gross					$ 450,000,000
Debt Instrument, Interest Rate, Stated Percentage					4.224%
Long-term Debt, Term					10 years
5.625% Senior Secured Note Due 2022 | Senior Secured Note | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%			5.625%
Long-term debt, Principal	$ 450,000,000			$ 450,000,000
Debt Instrument, Increase, Accrued Interest	$ 7,200,000
Extinguishment of Debt, Amount				$ 457,200,000