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, 2021

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, 2021 and 2020	5
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2021 and 2020	6
	Consolidated Balance Sheets – March 31, 2021 and December 31, 2020	7
	Consolidated Statements of Common Shareholder's Equity - March 31, 2021, and December 31, 2020	9
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2021 and 2020	10
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three Months Ended March 31, 2021 and 2020	11
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2021 and 2020	12
	Consolidated Balance Sheets – March 31, 2021 and December 31, 2020	13
	Consolidated Statements of Common Shareholder's Equity - March 31, 2021, and December 31, 2020	15
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2021 and 2020	16
	Notes
	Combined Notes to Consolidated Financial Statements	17
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	66
Item 4.	Controls and Procedures	66
Part II.	Other Information	67
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	67
Item 6.	Exhibits	67
Exhibit Index		68
Signatures		69

2

DEFINITIONS

ARO	Asset Retirement and Environmental Obligations
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EIM	Energy Imbalance Market
ERF	Expedited Rate Filing
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 Liquid Natural Gas, LLC
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
TCJA	Tax Cuts and Jobs Act
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 recent global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities) 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 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;

● The ability to maintain effective internal controls over financial reporting and operational processes;

● 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, 2020.

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,
	2021		2020
Operating revenue:
Electric	$	758,592	$	669,090
Natural Gas	392,906		371,031
Other	8,588		6,009
Total operating revenue	1,160,086		1,046,130
Operating expenses:
Energy costs:
Purchased electricity	205,410		165,742
Electric generation fuel	60,418		63,624
Residential exchange	(25,802)		(24,634)
Purchased natural gas	155,015		154,876
Unrealized (gain) loss on derivative instruments, net	(23,002)		48,541
Utility operations and maintenance	160,540		154,922
Non-utility expense and other	9,906		12,962
Depreciation & Amortization	208,431		164,816
Conservation amortization	34,060		27,393
Taxes other than income taxes	110,310		105,504
Total operating expenses	895,286		873,746
Operating income (loss)	264,800		172,384
Other income (expense):
Other income	13,630		14,059
Other expense	(1,510)		(2,282)
Interest charges:
AFUDC	3,586		3,643
Interest expense	(89,360)		(88,884)
Income (loss) before income taxes	191,146		98,920
Income tax (benefit) expense	2,153		3,984
Net income (loss)	$	188,993	$	94,936

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,
	2021		2020
Net income (loss)	$	188,993	$	94,936
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $634 and $1,373, respectively	2,385		5,170
Other comprehensive income (loss)	2,385		5,170
Comprehensive income (loss)	$	191,378	$	100,106

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, 2021		December 31, 2020
Utility plant (at original cost, including construction work in progress of $749,572 and $712,204 respectively):
Electric plant	$	9,288,156	$	9,200,231
Natural gas plant	4,296,864		4,227,532
Common plant	1,085,442		1,116,524
Less: Accumulated depreciation and amortization	(3,736,675)		(3,671,094)
Net utility plant	10,933,787		10,873,193
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	327,674		324,184
Total other property and investments	1,984,187		1,980,697
Current assets:
Cash and cash equivalents	36,507		52,307
Restricted cash	24,443		29,544
Accounts receivable, net of allowance for doubtful accounts of $30,392 and $20,080, respectively	374,296		352,132
Unbilled revenue	219,450		221,871
Materials and supplies, at average cost	117,891		118,333
Fuel and natural gas inventory, at average cost	38,743		48,795
Unrealized gain on derivative instruments	47,221		33,015
Prepaid expense and other	49,630		45,746
Power contract acquisition adjustment gain	15,694		14,874
Total current assets	923,875		916,617
Other long-term and regulatory assets:
Power cost adjustment mechanism	71,257		82,801
Purchased gas adjustment receivable	46,787		87,655
Regulatory assets related to power contracts	11,398		11,728
Other regulatory assets	737,377		747,651
Unrealized gain on derivative instruments	4,925		8,805
Power contract acquisition adjustment gain	75,601		80,900
Operating lease right-of-use asset	194,245		172,167
Other	86,680		80,751
Total other long-term and regulatory assets	1,228,270		1,272,458
Total assets	$	15,070,119	$	15,042,965

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, 2021		December 31, 2020
Capitalization
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—	$	—
Additional paid-in capital	3,313,532		3,313,532
Retained earnings	1,078,841		912,787
Accumulated other comprehensive income (loss), net of tax	(84,052)		(86,437)
Total common shareholder’s equity	4,308,321		4,139,882
Long-term debt:
First mortgage bonds and senior notes	4,212,000		4,212,000
Pollution control bonds	161,860		161,860
Long-term debt	1,733,500		1,724,700
Debt discount issuance costs and other	(203,026)		(206,120)
Total long-term debt	5,904,334		5,892,440
Total capitalization	10,212,655		10,032,322
Current liabilities:
Accounts payable	324,037		342,404
Short-term debt	191,000		373,800
Current maturities of long-term debt	526,345		526,412
Accrued expenses:
Taxes	134,228		110,752
Salaries and wages	35,295		42,530
Interest	79,400		73,647
Unrealized loss on derivative instruments	19,839		31,441
Power contract acquisition adjustment loss	2,036		2,039
Operating lease liabilities	19,238		19,204
Other	88,335		73,385
Total current liabilities	1,419,753		1,595,614
Other long-term and regulatory liabilities:
Deferred income taxes	846,692		810,729
Unrealized loss on derivative instruments	24,332		29,833
Regulatory liabilities	735,368		732,498
Regulatory liability for deferred income taxes	924,567		953,274
Regulatory liabilities related to power contracts	91,295		95,774
Power contract acquisition adjustment loss	9,362		9,689
Operating lease liabilities	182,288		160,980
Other deferred credits	623,807		622,252
Total long-term and regulatory liabilities	3,437,711		3,415,029
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	15,070,119	$	15,042,965

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				Accumulated Other
	Shares	Amount		Paid-in capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2019	200	$	—	$	3,308,957	$	775,491	$	(84,149)	$	4,000,299
Net income (loss)	—	—		—		94,936		—		94,936
Common stock dividend paid	—	—		—		(22,645)		—		(22,645)
Other comprehensive income (loss)	—	—		—		—		5,170		5,170
Balance at March 31, 2020	200	$	—	$	3,308,957	$	847,782	$	(78,979)	$	4,077,760
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

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,
	2021		2020
Operating activities:
Net Income (loss)	$	188,993	$	94,936
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	208,431		164,816
Conservation amortization	34,060		27,393
Deferred income taxes and tax credits, net	6,622		8,602
Net unrealized (gain) loss on derivative instruments	(23,002)		48,541
AFUDC - equity	(5,780)		(5,603)
Production tax credit utilization	(45,178)		(23,543)
Other non-cash	3,518		(6,075)
Regulatory assets and liabilities	(14,351)		(16,865)
Purchased gas adjustment	40,868		41,429
Other long term assets and liabilities	(5,695)		(27,016)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(19,743)		24,120
Materials and supplies	442		1,072
Fuel and natural gas inventory	10,052		14,497
Prepayments and other	(3,884)		251
Accounts payable	(14,868)		(45,236)
Taxes payable	23,476		21,178
Other	(512)		(11,126)
Net cash provided by (used in) operating activities	383,449		311,371
Investing activities:
Construction expenditures - excluding equity AFUDC	(213,781)		(223,707)
Other	362		(233)
Net cash provided by (used in) investing activities	(213,419)		(223,940)
Financing activities:
Change in short-term debt, net	(182,800)		(100,000)
Dividends paid	(22,939)		(22,645)
Proceeds from long-term debt and bonds issued	8,800		7,400
Redemption of bonds and notes	(66)		—
Other	6,074		3,670
Net cash provided by (used in) financing activities	(190,931)		(111,575)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(20,901)		(24,144)
Cash, cash equivalents, and restricted cash at beginning of period	81,851		66,146
Cash, cash equivalents, and restricted cash at end of period	$	60,950	$	42,002
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	77,160	$	78,636
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	54,805	$	56,699

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,
	2021		2020
Operating revenue:
Electric	$	758,592	$	669,090
Natural Gas	392,906		371,031
Other	8,588		6,009
Total operating revenue	1,160,086		1,046,130
Operating expenses:
Energy costs:
Purchased electricity	205,410		165,742
Electric generation fuel	60,418		63,624
Residential exchange	(25,802)		(24,634)
Purchased natural gas	155,015		154,876
Unrealized (gain) loss on derivative instruments, net	(23,002)		48,541
Utility operations and maintenance	160,540		154,922
Non-utility expense and other	9,418		12,735
Depreciation & Amortization	208,362		164,771
Conservation amortization	34,060		27,393
Taxes other than income taxes	110,310		105,504
Total operating expenses	894,729		873,474
Operating income (loss)	265,357		172,656
Other income (expense):
Other income	11,034		11,283
Other expense	(1,510)		(2,282)
Interest charges:
AFUDC	3,586		3,643
Interest expense	(62,371)		(60,714)
Income (loss) before income taxes	216,096		124,586
Income tax (benefit) expense	16,626		13,265
Net income (loss)	$	199,470	$	111,321

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,
	2021		2020
Net income (loss)	$	199,470	$	111,321
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,185 and $2,047, respectively	4,458		7,710
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $26, respectively	96		96
Other comprehensive income (loss)	4,554		7,806
Comprehensive income (loss)	$	204,024	$	119,127

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, 2021		December 31, 2020
Utility plant (at original cost, including construction work in progress of $749,572 and $712,204, respectively):
Electric plant	$	11,116,750	$	11,035,402
Natural Gas plant	4,855,247		4,786,419
Common plant	1,107,719		1,139,120
Less:  Accumulated depreciation and amortization	(6,145,929)		(6,087,748)
Net utility plant	10,933,787		10,873,193
Other property and investments:
Other property and investments	83,620		83,855
Total other property and investments	83,620		83,855
Current assets:
Cash and cash equivalents	36,051		51,177
Restricted cash	24,443		29,544
Accounts receivable, net of allowance for doubtful accounts of $30,392 and $20,080, respectively	376,228		355,850
Unbilled revenue	219,450		221,871
Materials and supplies, at average cost	117,891		118,333
Fuel and natural gas inventory, at average cost	37,479		47,531
Unrealized gain on derivative instruments	47,221		33,015
Prepaid expense and other	49,630		45,746
Total current assets	908,393		903,067
Other long-term and regulatory assets:
Power cost adjustment mechanism	71,257		82,801
Purchased gas adjustment receivable	46,787		87,655
Other regulatory assets	737,377		747,651
Unrealized gain on derivative instruments	4,925		8,805
Operating lease right-of-use asset	194,245		172,167
Other	85,294		79,231
Total other long-term and regulatory assets	1,139,885		1,178,310
Total assets	$	13,065,685	$	13,038,425

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, 2021		December 31, 2020
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	1,023,818		876,401
Accumulated other comprehensive income (loss), net of tax	(176,402)		(180,956)
Total common shareholder’s equity	4,333,380		4,181,409
Long-term debt:
First mortgage bonds and senior notes	4,212,000		4,212,000
Pollution control bonds	161,860		161,860
Debt discount, issuance costs and other	(35,337)		(35,816)
Total long-term debt	4,338,523		4,338,044
Total capitalization	8,671,903		8,519,453
Current liabilities:
Accounts payable	324,152		342,504
Short-term debt	191,000		373,800
Current maturities of long-term debt	2,345		2,412
Accrued expenses:
Taxes	130,781		107,254
Salaries and wages	35,295		42,530
Interest	58,002		48,189
Unrealized loss on derivative instruments	19,839		31,441
Operating lease liabilities	19,238		19,204
Other	88,335		73,385
Total current liabilities	868,987		1,040,719
Other long-term and regulatory liabilities:
Deferred income taxes	1,038,347		987,382
Unrealized loss on derivative instruments	24,332		29,833
Regulatory liabilities	734,104		731,234
Regulatory liabilities for deferred income tax	925,277		953,987
Operating lease liabilities	182,288		160,980
Other deferred credits	620,447		614,837
Total long-term and regulatory liabilities	3,524,795		3,478,253
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	13,065,685	$	13,038,425

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				Accumulated Other
	Shares	Amount		Paid-in capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2019	85,903,791	$	859	$	3,485,105	$	751,193	$	(188,477)	$	4,048,680
Net income (loss)	—	—		—		111,321		—		111,321
Common stock dividend paid	—	—		—		(53,794)		—		(53,794)
Other comprehensive income (loss)	—	—		—		—		7,806		7,806
Balance at March 31, 2020	85,903,791	$	859	$	3,485,105	$	808,720	$	(180,671)	$	4,114,013
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

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,
	2021		2020
Operating activities:
Net Income (loss)	$	199,470	$	111,321
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	208,362		164,771
Conservation amortization	34,060		27,393
Deferred income taxes and tax credits, net	21,044		12,215
Net unrealized (gain) loss on derivative instruments	(23,002)		48,541
AFUDC - equity	(5,780)		(5,603)
Production tax credit utilization	(45,178)		(23,543)
Other non-cash	885		(8,711)
Regulatory assets and liabilities	(14,351)		(16,865)
Purchased gas adjustment	40,868		41,429
Other long term assets and liabilities	(3,077)		(23,801)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(17,957)		25,892
Materials and supplies	442		1,072
Fuel and natural gas inventory	10,052		14,497
Prepayments and other	(3,884)		251
Accounts payable	(14,853)		(36,201)
Taxes payable	23,527		26,850
Other	3,549		(7,607)
Net cash provided by (used in) operating activities	414,177		351,901
Investing activities:
Construction expenditures - excluding equity AFUDC	(205,927)		(225,612)
Other	362		(233)
Net cash provided by (used in) investing activities	(205,565)		(225,845)
Financing activities:
Change in short-term debt, net	(182,800)		(100,000)
Dividends paid	(52,053)		(53,794)
Redemption of bonds and notes	(66)		—
Other	6,080		3,668
Net cash provided by (used in) financing activities	(228,839)		(150,126)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(20,227)		(24,070)
Cash, cash equivalents, and restricted cash at beginning of period	80,721		64,891
Cash, cash equivalents, and restricted cash at end of period	$	60,494	$	40,821
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	47,749	$	47,115
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	54,805	$	56,699

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 Puget Sound Energy. 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, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. 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 FASB 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. 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, 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 2020 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 governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment.

The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2021 and 2020:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020
Allowance for credit losses:
Beginning balance	$	20,080	$	8,294
Provision for credit loss expense	12,452		4,894
Receivables charged-off	(2,140)		(3,374)
Total ending allowance balance	$	30,392	$	9,814

16

Tacoma LNG Facility

In August 2015, PSE filed a proposal with the Washington Commission to develop a liquified natural gas (LNG) facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. A meeting with the Washington Pollution Control Hearings Board occurred in April 2021 and a decision is forthcoming. The facility achieved mechanical completion in February 2021, however, it remains nonoperational as additional construction and testing are completed.

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, $239.4 million and $231.6 million of 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, 2021 and December 31, 2020, respectively. Additionally, $0.2 million and $0.3 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, 2021, and March 31, 2020, respectively. Additionally, $216.5 million and $207.7 million of 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, 2021 and December 31, 2020, 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 $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income and $3.6 million is included in accounts payable on the Company's consolidated balance sheet for the quarter ended March 31, 2021.

(2)  New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued 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 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, 2021, 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 table presents disaggregated revenue from contracts with customers, and other revenue by major source:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31,
Revenue from contracts with customers:	2021		2020
Electric retail	$	664,102	$	607,693
Natural gas retail	387,863		365,637
Other	56,129		43,774
Total revenue from contracts with customers	1,108,094		1,017,104
Alternative revenue programs	(1,928)		1,150
Other non-customer revenue	53,920		27,876
Total operating revenue	$	1,160,086	$	1,046,130

Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services.

Electric and Natural Gas Retail Revenue

Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis.

Electric Transmission and Natural Gas Transportation Revenue

Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.

18

Biogas

Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.

Wholesale

Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser.

Other Revenue

In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance.

Transaction Price Allocated to Remaining Performance Obligations

In December 2020, PLNG entered into a contract with one customer where PLNG 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) fluctuating 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 of 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, 2021					December 31, 2020
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	32,366	$	33,743	*	$	22,544	$	46,922
Natural gas derivatives (MMBtus)3	331	19,780		10,428		320	19,276		14,352
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274
Current		$	47,221	$	19,839		$	33,015	$	31,441
Long-term		4,925		24,332			8,805		29,833
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274

_______________

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 purchased gas adjustment (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 221.4 million One Million British Thermal Units (MMBtu) and purchased electricity of

4.4 million Megawatt Hours (MWhs) at March 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020.

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, 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	$	52,146	$	—	$	52,146	$	(21,105)	$	—	$	31,041
Liabilities:
Energy derivative contracts	$	44,171	$	—	$	44,171	$	(21,105)	$	(143)	$	22,923

Puget Energy and Puget Sound Energy	At December 31, 2020
	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	$	41,820	$	—	$	41,820	$	(21,696)	$	—	$	20,124
Liabilities:
Energy derivative contracts	$	61,274	$	—	$	61,274	$	(21,696)	$	(9,343)	$	30,235

_______________

1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting 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	2021		2020
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	1,628	$	(9,755)
Realized	Electric generation fuel	8,313		1,296
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	21,374		(38,786)
Realized	Purchased electricity	(13,303)		(5,935)
Total gain (loss) recognized in income on derivatives		$	18,012	$	(53,180)

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, 2021, approximately 99.2% 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 0.8% 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 NGX exchange 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, 2021, PSE had cash posted as collateral of $3.2 million related to contracts executed on the ICE platform. Also, as of March 31, 2021, PSE had $12.0 million in cash posted as collateral and a $1.0 million 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, 2021.

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, 2021						At December 31, 2020
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	21,991	$	—	$	21,991	$	26,966	$	—	$	26,966
Requested credit for adequate assurance	7,330		—		—		6,576		—		—
Forward value of contract3	143		11,990		N/A		9,343		20,903		N/A
Total	$	29,464	$	11,990	$	21,991	$	42,885	$	20,903	$	26,966

_______________

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 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.

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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 $52.0 million and $52.7 million at March 31, 2021 and December 31, 2020 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, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	5,670,834	$	7,063,347	$	5,667,740	$	7,755,946
Long-term debt (variable-rate)	2	233,500		233,500		224,700		224,700
Total liabilities		$	5,904,334	$	7,296,847	$	5,892,440	$	7,980,646

Puget Sound Energy		March 31, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358
Total liabilities		$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358

_______________

1 The carrying value includes debt issuances costs of $21.9 million and $22.7 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.6 million and $22.9 million for March 31, 2021 and December 31, 2020, 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. 2021						Fair Value At December 31, 2020
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	31,980	$	386	$	32,366	$	21,947	$	597	$	22,544
Natural gas derivative instruments	19,677		103		19,780		19,139		137		19,276
Total assets	$	51,657	$	489	$	52,146	$	41,086	$	734	$	41,820
Liabilities:
Electric derivative instruments	$	12,187	$	21,556	$	33,743	$	22,607	$	24,315	$	46,922
Natural gas derivative instruments	8,491		1,937		10,428		13,080		1,272		14,352
Total liabilities	$	20,678	$	23,493	$	44,171	$	35,687	$	25,587	$	61,274

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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)	2021						2020
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	820		—		820		(24,552)		—		(24,552)
Included in regulatory assets / liabilities	—		(888)		(888)		—		323		323
Settlements	1,728		189		1,917		1,626		(513)		1,113
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		—		—		—
Balance at end of period	$	(21,170)	$	(1,834)	$	(23,004)	$	(26,305)	$	1,092	$	(25,213)

_______________

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 $0.8 million and zero for three months ended March 31, 2021 and 2020, 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, 2021

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	386	$	21,556	Discounted cash flow	Power prices (per MWh)	$	22.87	$	44.21	$	32.56
Natural gas	$	103	$	1,937	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.10	$	3.57	$	2.70

_______________

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

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The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	597	$	24,315	Discounted cash flow	Power prices (per MWh)	$	22.82	$	41.66	$	31.54
Natural gas	$	137	$	1,272	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.89	$	3.42	$	2.47

___________

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, 2021, and December 31, 2020, 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 $4.9 million and $5.5 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, 2021, 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".

The following table presents the impairment recorded to the Company's intangible asset contracts in 2020, with corresponding reductions to the regulatory liability:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value	Fair Value	Write Down
March 31, 2020	Rocky Reach	$147,168	$94,603	$52,565

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The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. The unobservable input averages disclosed below represent the arithmetic average of the inputs and are not weighted by volume. A less significant input is the discount rate reflective of a market participant's cost of capital used in the valuation.

The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase

contracts' fair value:

Puget Energy
Valuation Date	Unobservable Input	Low	High	Average
March 31, 2020	Power prices (per MWh)	$10.23	$29.05	$20.88
	Power contract costs per quarter (in thousands)	$6,308	$7,085	$6,468

(6) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees.  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.  Starting January 1, 2014, all the United Association of Plumbers and Pipefitters (UA) represented employees receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014, for employees represented by the International Brotherhood of Electrical Workers Union (IBEW), participants receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited 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 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. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries.

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.

In 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.

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The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2021 and 2020:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,502)		—		—		(91)		(97)
Amortization of prior service cost	(476)		(495)		87		87		2		—
Amortization of net loss (gain)	2,830		1,981		587		586		(10)		(22)
Net periodic benefit cost	$	2,562	$	1,279	$	1,082	$	1,279	$	19	$	21

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,504)		—		—		(91)		(97)
Amortization of prior service cost	(378)		(393)		87		87		2		—
Amortization of net loss (gain)	5,311		4,656		635		659		(15)		(36)
Net periodic benefit cost	$	5,141	$	4,054	$	1,130	$	1,352	$	14	$	7

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The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2021 and December 31, 2020:

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, 2021		December 31, 2020		March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
Change in benefit obligation:
Benefit obligation at beginning of period	$	849,383	$	774,305	$	46,742	$	63,000	$	12,114	$	11,627
Amendments	—		—		—		—		—		44
Service cost	6,711		24,337		115		756		41		190
Interest cost	5,578		25,180		293		1,464		77		368
Curtailment Loss / (Gain)	—		—		—		—		—		—
Actuarial loss (gain)	—		69,413		—		3,663		—		604
Benefits paid	(11,625)		(42,775)		(496)		(22,141)		(237)		(906)
Medicare part D subsidy received	—		—		—		—		196		187
Administrative Expense	—		(1,077)		—		—		—		—
Benefit obligation at end of period	$	850,047	$	849,383	$	46,654	$	46,742	$	12,191	$	12,114

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, 2021, are expected to be at least $18.0 million, $6.8 million and $0.3 million, respectively. During the three months ended March 31, 2021, the Company contributed $0.5 million to fund the SERP. During the three months ended March 31, 2020, the Company contributed $13.6 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans.

(7) Regulation and Rates

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, the parties to the PCORC reached a multiparty settlement in principle, with Public Counsel not joining the settlement, but also not opposing. The settlement agreement and supporting testimony was filed with the Washington Commission on April 2, 2021, who held hearings on the matter on April 22, 2021. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1% and, pending approval by the Washington Commission, is expected to be effective June 2021.

General Rate Case

PSE filed a general rate case (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. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes

29

that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony that included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas, PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

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, which 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%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of depreciation expense associated with PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which 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 $27.7 million, or 1.3%, and the natural gas increase to $0.2 million, or 0.02%.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) 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. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is 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 will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling.

Expedited Rate Filing

On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million rate increase for natural

30

gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.

The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s then-next GRC, filed June 20, 2019, and discussed above:

1)excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019;

2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and

3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.

The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its AMI investment and may defer the return on the AMI investment that was included in the test year of the filing. As noted above, the 2019 GRC effectively ends all deferrals of AMI depreciation expense and deferrals of return on additional AMI investments will be evaluated in future proceedings. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform.  The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas and became effective May 1, 2018, by operation of law.

The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

While the settlement agreement in the ERF provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts through the PSE Schedule 141X tariff, the ongoing treatment of excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences was left to be addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owed to customers will be greater than $0.1 million, PSE would submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021. As this balance was greater than $0.1 million, PSE filed tariff revisions on July 20, 2020 and the Washington Commission approved the filing on August 27, 2020. Finally, the GRC final order determined that PSE is required to pass back 2019 and 2020 protected excess deferred tax reversals totaling $70.8 million over the 12 months following the rate effective period through PSE’s Schedule 141X tariff. The GRC final order also determined that PSE is required to pass back unprotected excess deferred tax balances totaling $38.9 million over 36 months following the rate effective period through PSE’s Schedule 141Z tariff. Further details of the outcome associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.

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. Since 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas

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operating revenues related to electric transmission and distribution, natural gas operations and general administrative 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 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. 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 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

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 as of August 31, 2020 of about $16.0 million for electric delivery and fixed power cost decoupling 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. As part of this filing, PSE will true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On March 31, 2021, 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 $0.9 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; 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.

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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, 2021, in its PCA mechanism, PSE under recovered its allowable costs by $11.4 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 $25.1 million for the three months ended March 31, 2020, of which $4.0 million was apportioned to customers and accrued $0.5 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing

On July 1, 2019, 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 effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.

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 2019. 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. Due to concerns about the economic impact of the COVID-19 pandemic on customers, PSE voluntarily, with Washington Commission Staff support, delayed filing an increase to its Schedule 95 rates in its annual PCA report filing in Docket UE-200398, which was approved on July 30, 2020. Subsequently, PSE filed to recover the deferred balance in Docket UE-200893, effective December 1, 2020, and the Washington Commission approved PSE’s request on November 24, 2020. During 2019, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $67.2 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.2 million of the under-recovered amount, and customers were responsible for the remaining $36.0 million, or $37.0 million including interest. As PSE had an approved balance owing from customers including interest at the start of 2019 totaling $4.7 million, the approved cumulative deferral balance for the PCA, as of December 2019, is $41.7 million. As previously stated, this filing is set to collect the customer’s share of the cumulative 2019 imbalance in PSE’s PCA mechanism.

Purchased Gas Adjustment Mechanism

On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020.

On October 24, 2019, the Washington Commission approved PSE’s request for PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the PGA rates effective November 1, 2018; and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events that winter experienced by PSE: the rupture of a pipeline owned by Enbridge, Inc. in October 2018, unusually low temperatures in

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February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two-year period, instead of the historic one-year period, from November 2019 through October 2021.

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 the portion of PGA amortization balances originally filed through the annual November 1, 2019 PGA filing under the Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of the originally approved two-year period.

On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.

The following table presents the PGA mechanism balances and activity at March 31, 2021 and December 31, 2020:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2021		2020
PGA receivable beginning balance	$	87,655	$	132,766
Actual natural gas costs	113,175		314,792
Allowed PGA recovery	(154,592)		(363,886)
Interest	549		3,983
PGA receivable ending balance	$	46,787	$	87,655

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. For the period ended March 31, 2021 and December 31, 2020, PSE deferred $4.6 million and $2.8 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% per the 2018 ERF. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and on July 8, 2020, the Washington Commission issued its order in PSE’s 2019 GRC. 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 next GRC. 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 with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is 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 puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. The program ended on September 30, 2020.

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On March 28, 2021 the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance for each qualifying low-income household, per program year, with a total program budget of $20.0 million for electric customers and $7.7 million for natural gas customers.

Storm Damage Deferral Accounting

The Washington Commission has defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm 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, 2021, PSE incurred $23.3 million in storm-related electric transmission and distribution system restoration costs, of which $12.9 million and $0.2 million was deferred as regulatory assets related to storms that occurred in 2021 and 2020, respectively. This compares to $9.9 million incurred in storm-related electric transmission and distribution system restoration costs for the three months ended March 31, 2020, of which the Company deferred zero as regulatory assets related to storms that occurred in 2020. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; 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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and the operator of Colstrip, Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The 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 Transition 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 December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would have retained its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's ownership. The proposed agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE had agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval.

On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. However, after evaluating the likelihood of the regulatory approval process in both Washington and Montana, on October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and the proposed power purchase agreement and relieve all claims against one another arising out of or relating to the sale agreement. The termination of the proposed sale and proposed PPA resulted in the withdrawal of PSE's filing with the Washington Commission. Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2020.

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Other Commitments and Contingencies

In addition 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, 2020, during the three months ended March 31, 2021, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $777.4 million through 2042.

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 period ended December 31, 2020.

COVID-19

The outbreak of the Coronavirus Disease 2019 (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The full impact on the Company's business from the pandemic, including governmental and regulatory response actions, is unknown at this time and difficult to predict. 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.

Government mandated stay at home orders and private work from home mandates due to COVID-19 have affected electric and gas loads for residential, commercial, and industrial customers. During the quarter ended March 31, 2021, the Company delivered marginally higher electric and decreased natural gas loads of 0.1% and 3.7%, respectively, when comparing weather-adjusted actual to forecast. Decreases in commercial and industrial loads were partially offset by increases in residential loads. Electric retail revenue marginal increases included reduced electric supply costs and the effects of decoupling. The impact on natural gas revenue due to load was offset by gas supply cost and decoupling. The Company anticipates that electric and gas loads will continue to be impacted for the remainder of 2021, due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus.

At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to its customers. The Company has flexibility with capital investments and other measures to maintain sufficient liquidity over the next twelve months. The situation remains fluid and future impacts to the Company that are presently unknown or unanticipated may occur. Furthermore, the severity of impact to the Company could increase the longer the global pandemic persists.

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, 2021, PSE deferred no costs related to this petition specific to COVID-19.

(9)  Leases

Other than the item discussed below, there have been no significant changes regarding the Company's leases as described in Note 9 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million.

(10) Other

Long-Term Debt

As of March 31, 2021, Puget Energy maintained an $800.0 million credit facility, of which $23.5 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 10K for the year ended December 31, 2020.

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Short-Term Debt

As of March 31, 2021, no amount was drawn under PSE's credit facility and $191.0 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 10K for the year ended December 31, 2020.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. 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, 2020. 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 COVID-19 pandemic.

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its 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, currently 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 Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCIMC was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17th, 2019. 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.

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COVID-19 Update

A novel strain of coronavirus was first identified in December 2019, and Coronavirus Disease 2019 (COVID-19) was subsequently declared a pandemic by the World Health Organization. To date, COVID-19 has surfaced in nearly all regions around the world and resulted in travel restrictions and business slowdowns or shutdowns in affected areas. On January 21, 2020, authorities confirmed the first COVID-19 case in Washington State, followed by the first confirmed virus-related death in Washington State on February 29, 2020, in each case, in the Company’s service territory.

In response to the outbreak and business disruption, the Company prioritized the health and safety of our customers, employees, and the communities in our service territory implementing a number of changes including the following: a) not disconnecting customers for non-payment; b) receiving Washington Commission approval to waive late fees; c) filing a motion with the Washington Commission to waive the statutory deadline for the Company’s GRC for up to 60 days, from May 20, 2020, until July 20, 2020; d) establishing a Crisis-Affected Customer Assistance Program (CACAP); and e) implementing social distancing measures for our employees and using remote workforce where possible. PSE continues to serve our customers and has implemented business continuity and emergency response plans and enhanced safety protocols to continue to provide electricity and natural gas services to customers and otherwise support the Company’s operations.

We are continuing to monitor developments involving our workforce, customers, electricity and natural gas demand, commodity costs and suppliers but cannot predict the impact of COVID-19 on our results of operations, financial condition and ongoing operations. An extended slowdown of the United States' economic growth, demand for commodities and/or material changes in governmental policy could result in lower economic growth and lower demand for electricity and natural gas in our service territory. Moreover, such extended slowdown will affect the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and ongoing operations.

Due to continued stay at home orders, work from home mandates, and business disruptions caused by COVID-19, electric and natural gas loads increased 0.1% and decreased 3.7%, respectively, during the year ended March 31, 2021. Residential electric and natural gas loads during the year ended March 31, 2021, increased 5.0% and decreased 4.2%, respectively due to COVID-19. In contrast, COVID-19 impacts on commercial electric and natural gas loads resulted in decreases of 6.6% and 8.6%, respectively, during the year ended March 31, 2021. Revenue reductions are partially offset by the effects of decoupling and reduced electric and natural gas supply costs. Decoupling revenue during the quarter was over collected by $4.8 million and recognized $0.2 million for electric and natural gas, respectively as compared to $7.8 million and $1.4 million revenue recognized in the same period of 2020 for electric and natural gas, respectively. The Company anticipates that electric and natural gas loads will continue to be impacted due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus. Risks to these assumptions include the duration, severity, and potential resurgence of the virus, government proclamations related to managing public health, and fiscal stimulus policies to support economic recovery. Industrial customers, who represent 3.3% of the Company's total retail revenue and are generally transmission and transportation services which are not volumetric in nature, are not expected to be materially impacted.

Due to business disruptions caused by the COVID-19 pandemic, the Company has incurred increased costs and partially offsetting cost savings that have been immaterial through the period ended March 31, 2021. To the extent that the Company incurs material, unexpected expenses associated with the COVID-19 pandemic, such as increased uncollectible accounts receivable, the Company will continue to explore regulatory accounting policies and rate recovery mechanisms to address any negative impacts to financial results. 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, 2021, PSE deferred no costs specific to COVID-19.

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 $13.7 million as of March 31, 2021.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended March 31, 2021, is set forth below in this "Overview" section as well as in other sections of Management's Discussion and Analysis.

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Factors and Trends Affecting PSE's Performance

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2021 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, or the impact of civil unrest to infrastructure or preventing access to infrastructure; 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.

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2021 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 on a regular and frequent basis in the foreseeable future. In addition, 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.

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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.

On April 15, 2021, the Washington State Legislature passed a bill that would require investor-owned utilities to file a multiyear rate plan for two, three, or four years as part of General Rate Cases filed with the Washington Commission on or after January 1, 2022. The legislation allows companies to include a request to include a fair value measure of plant in service as of the date that rates go into effect. Utilities would be bound to the first and second year of a multiyear rate plan and can file for a new rate plan in years three or four. If a company earns greater than a half percent above its authorized rate of return on a regulated basis, revenues above the level must be deferred for later return to customers. The Washington Commission must also set performance measurements to be assessed in the multiyear rate plan. The bill is pending review by the Governor for approval or veto.

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 general rate case (GRC).

On December 9, 2020, PSE filed its 2020 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, the parties to the PCORC reached a multiparty settlement in principle, with Public Counsel not joining the settlement, but also not opposing. The settlement agreement and supporting testimony was filed with the Washington Commission on April 2, 2021, who held hearings on the matter on April 22, 2021. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1% and, pending approval by the Washington Commission, is expected to be effective June 2021.

General Rate Case Filing

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. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed supplemental testimony, which provided certain updates to the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony that included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

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 6.80% 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 purchased gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic, which 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%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a

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motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which 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 $27.7 million, or 1.3%, and the natural gas increase to $0.2 million, or 0.02%.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) 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 IRS normalization and consistency rules. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is 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 will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling.

For further details regarding the 2019 GRC filing, see Note 7, "Regulations and Rates" to the consolidated financial statements included in part 1 of this report.

Expedited Rate Filing

On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Washington Commission approved the settlement with one condition, that PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020.

For further details regarding the 2018 ERF, see Note 7, "Regulations and Rates" to the consolidated financial statements included in part 1 of this report.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform.  The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%. PSE began passing back protected deferred tax balances created by tax reform as determined in the ERF settlement agreement through PSE’s Schedule 141X tariff. The pass back of deferred tax balances was continued with the GRC final order which also created PSE’s Schedule 141Z tariff, in addition to Schedule 141X, to pass-back additional deferred tax balances. Further details of the outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the

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decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism is to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

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 required PSE to move amortization balances as of August 31, 2020 of about $16.0 million for electric delivery and fixed power cost decoupling to new decoupling amortization accounts 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 correct 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. As part of this filing, PSE will true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On March 31, 2021, 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 Accounting Standards Codification (ASC) 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a 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 $0.9 million of electric deferred revenue will not be collected within 24 months of the annual period, therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; 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, 2021	1.0%	$21.4
January 1. 2021	(1.0)	(20.6)
October 15, 20202	(0.5)	(10.2)
May 1, 2020	0.2	2.0
May 1, 2019	0.9	20.6
Natural Gas:
May 1, 2021	1.5%	$15.0
May 1, 2020	(0.5)	(4.8)
May 1, 2019	(5.3)	(45.9)

_______________

1.For the Electric rates effective May 1, 2021 there was $21.1 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2022 due to 3% rate cap; there was no excess earnings that impacted both electric and natural gas revenue change. For electric and natural gas rates effective May, 1, 2020 and May 1. 2019, there were no excess earnings that impacted the approved revenue change.

2.The 2019 GRC final order lengthened the recovery period from original one-year recovery to two-year recovery to April 2022.

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Electric Rates

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, 2021, in its PCA mechanism, PSE under recovered its allowable costs by $11.4 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 $25.1 million for the three months ended March 31, 2020, of which $4.0 million was apportioned to customers and accrued $0.5 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing

On July 1, 2019, 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 effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.

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 2019. 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. Due to concerns about the economic impact of the COVID-19 pandemic on customers, PSE voluntarily, with Washington Commission Staff support, delayed filing an increase to its Schedule 95 rates in its annual PCA report filing in Docket UE-200398, which was approved on July 30, 2020. Subsequently, PSE filed to recover the deferred balance in Docket UE-200893, effective December 1, 2020, and the Washington Commission approved PSE’s request on November 24, 2020. During 2019, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $67.2 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.2 million of the $67.2 million under-recovered amount, and customers were responsible for the remaining $36.0 million, or $37.0 million including interest. As PSE had an approved balance owing from customers including interest at the start of 2019 totaling $4.7 million, the approved cumulative deferral balance for the PCA as of December 2019 is $41.7 million. As previously stated, this filing is set to collect the customer’s share of the cumulative 2019 imbalance in PSE’s PCA mechanism.

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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, 2020	2.1%	$43.9
October 15, 2020	(0.2)	(3.3)
July 3, 2020	1.2	23.9
July 1, 20191	(1.2)	(24.9)
May 1, 2019	0.1	3.3

_______________

1.The rates for Microsoft Special Contracts portion was 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 become effective October 1, 2020.

Electric 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, 2021	(0.6)%	$(12.3)
May 1, 2020	0.9	17.8
May 1, 2019	(0.9)	(17.5)

Electric 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 was implemented in 2013 and 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, 2021	(0.1)%	$(1.9)
May 1, 2020	0.07	1.4
May 1, 2019	(0.2)	(5.1)

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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. Additionally, this tracker is impacted by the TCJA previously discussed. Accordingly, PSE filed for a one-time rate change to be effective May 1, 2018, to recognize the decrease in the federal corporate income tax rate from 35% to 21%.

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, 2021	0.3%	$(29.5)
January 1, 2020	(0.04)	(37.8)
January 1, 2019	0.1	(38.7)

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)
October 12, 2019	0.01%	$(81.8)

Natural Gas Rates

Natural Gas 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 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, 2021	(0.2)%	$(1.5)
May 1, 2020	0.4	3.5
May 1, 2019	0.1	1.1

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Natural Gas 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 was implemented in 2013 and 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, 2021	0.4%	$3.6
May 1, 2020	(0.3)	(2.8)
May 1, 2019	(0.2)	(1.6)

Natural Gas Cost Recovery Mechanism

The purpose of the cost recovery mechanism (CRM) is to recover capital 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.

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, 2020	1.2%	$10.6
November 1, 2019	0.8	7.0
November 1, 2018	0.5	5.0

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 April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the out-of-cycle PGA rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020.

On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the

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collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the rupture of a pipeline owned by Enbridge in October 2018, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.

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 the portion of PGA amortization balances originally filed through annual November 1, 2019 PGA filing under Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of originally approved two-year period.

On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.

The following table presents the PGA mechanism balances and activity at March 31, 2021 and December 31, 2020:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2021		2020
PGA receivable beginning balance	$	87,655	$	132,766
Actual natural gas costs	113,175		314,792
Allowed PGA recovery	(154,592)		(363,886)
Interest	549		3,983
PGA receivable ending balance	$	46,787	$	87,655

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, 2020	7.7%	$70.0
October 1, 2020	(3.9)	(35.5)
November 1, 20191	13.4	118.3
May 1, 20192	6.3	54.0

_______________

1.The 2019 GRC final order lengthened the recovery period from two to three years.

2.The rate for out of the cycle May 2019 PGA (Supplemental A) filing was set to zero effective May 1, 2020, The actual residual amount resulting was included in annual PGA filling effective November 1, 2020.

Other Proceedings

Microsoft Special Contract

Following discussions between PSE, the Microsoft Corporation, and others, and after completing a negotiated regulatory process, the Washington Commission issued an order in July 2017 approving a special contract between PSE and Microsoft relating to retail access for Microsoft loads currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to Microsoft must be carbon free, (iii) there will be no reduction in Microsoft's funding of PSE’s

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conservation programs, (iv) Microsoft paid a transition fee that was a straight pass-through to customers and (v) Microsoft will fund enhanced low-income support. Microsoft began taking service under the special contract on April 1, 2019, after meeting the eligibility requirements under the special contract.

Voluntary Long-Term Renewable Energy

Effective September 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product. This provides customers with electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000 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.

In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase two project is the 150 MW solar facility to be located in Klickitat County, WA. It is expected to achieve commercial operation in 2021 and serve twenty customers. The phase 2 offering will be a blend of the phase 1 wind and the solar facility. Phase 1 customers will receive wind through 2020 and then are expected to receive the blended energy later in 2021.

Crisis Affected Customer Assistance Program

On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is 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 puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. The program ended on September 30, 2020.

On March 28, 2021 the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance for each qualifying low-income household, per program year, with a total program budget of $20.0 million for electric customers and $7.7 million for natural gas customers.

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

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

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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 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; and therefore, PSE’s business has historically been recognized as a natural monopoly. However, PSE faces competition from public utility districts and municipalities that want to establish their own municipal-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, 2020, and 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 departure from GAAP presentation.  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.

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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, 2020 and 2021:

______________

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

Three Months Ended March 31, 2020 compared to 2021

Electric Operating Revenue

Electric operating revenues increased $89.5 million from the prior year primarily due to an increase in electric retail sales of $62.6 million, other revenues of $27.0 million, an increase in other decoupling revenue of $9.1 million and an increase in sales to other utilities of $3.4 million; partially offset by decoupling revenue of $12.6 million. These items are discussed in detail below.

•Electric retail sales increased $62.6 million due to an increase of $44.0 million in rates compared to the prior year and $18.6 million from an increase in retail electricity usage of 2.7%. The increase in rates is primarily due to the tariffs effective October 15, 2020 filed pursuant to the Company's most recent GRC. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes. The additional usage was due to an increase in residential usage of 5.1%, which was driven by an increase in heating degree days of 3.1% and an increase in retail customers of 1.3% compared to 2020.

•Sales to other utilities increased $3.4 million or 20.2% due to a 49.5% increase in the actual price of sales combined with a 19.6% decrease in volumes. The increase to the actual price of sales was due to higher market power prices, which were 42.7% higher than in 2020. Lower sales volumes were the result of 88.4% higher natural gas prices which reduced market heat rates and caused PSE’s natural gas-fueled generators to run less frequently.

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•Decoupling revenue decreased $12.6 million, primarily attributable to a $6.8 million and $5.8 million decrease in delivery and fixed production cost (FPC) deferral revenues respectively in the current period compared to the same period in 2020. This was driven by increased usage as noted above in the retail revenue section. This resulted in actual delivery and FPC deferral revenues being greater than allowed delivery deferral revenues in the current year, whereas in the prior year actual revenues were lower compared to allowed revenues.

•Other decoupling revenue increased $9.1 million, primarily due to a $7.1 million increase related to GAAP alternative revenue program recognition guidelines. In 2020, there were $7.1 million of decoupling revenue that was not anticipated to be collected within 24 months, and therefore was deferred. This amount was recognized in the first quarter of 2021, when the alternative revenue program revenue recognition guidelines were met. Also there was a $2.0 million decrease year-over-year in amortization of prior year undercollections due to a decrease in amortization rates related to an increase in the amortization period from 1 to 2 years as a result of the GRC.

•Transportation and other revenue increased $27.0 million primarily due to an increase in production tax credit (PTC) deferral revenue of $21.6 million for the re-purpose of the PTCs driven by an increase in current period taxable income. Additionally, there was an increase in net wholesale non-core gas sales of $10.7 million; partially offset by an increase in tax reform deferrals in 2021 for revenue subject to refunds of $6.2 million. The change in net wholesale non-core gas sales was primarily due to a $10.2 million increase in sales driven by a 79% increase in the average price of the non-core gas sold in 2021 compared to 2020, offset by a 12% decrease in sales volume. Natural gas prices rose in 2021 during the February cold weather event and Texas power and gas crisis but returned to more normal levels by the end of the period.

Electric Power Costs

Electric power costs increased $35.2 million primarily due to an increase of $39.7 million of purchased electricity costs; partially offset by $3.2 million of electric generation fuel expenses and $1.2 million of residential exchange credits. These items are discussed in detail below.

•Purchased electricity expense increased $39.7 million primarily due to a 16.9% increase in wholesale electricity purchases and a 6.0% increase in wholesale prices. The increase in purchases was primarily driven by an increase in load as well as an increase in other contracted resources and non-firm energy of 36.7% and 17.0%, respectively, driving a 21.3% decrease in combustion turbine generation as natural gas costs increased 88.4% .

•Electric generation fuel expense decreased $3.2 million primarily due to a $3.2 million decrease in combustion turbine (CT) generation costs primarily driven by a 21.3% decrease in CT production driven by the cost of natural gas and increase in wholesale purchases.

•Residential exchange expense credits increased $1.2 million compared to the same period in 2020 as a result of higher electric residential sales volumes associated with the BPA residential exchange program. The residential exchange credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

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.

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The following chart displays the details of PSE's natural gas margin changes for the three months ended March 31, 2020 and 2021:

_______________

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

Three Months Ended March 31, 2020 compared to 2021

Natural Gas Operating Revenue

Natural gas operating revenue increased $21.9 million primarily due to an increase of $23.1 million in total retail sales and an increase of $1.7 million in other decoupling revenue; partially offset by a decrease of $1.2 million in decoupling revenue and a $1.8 million decrease in transportation and other revenue. These items are discussed in detail below.

•Natural gas retail sales revenue increased $23.1 million due to an increase in rates of $14.5 million and an increase in natural gas load of 2.5%, or $8.6 million of natural gas sales. The increase in rates is primarily due to the PGA increase effective November 1, 2020 and the tariffs effective October 1, 2020 filed pursuant to the Company's most recent GRC. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. Natural gas load increased primarily due to an increase in usage by residential, commercial and industrial customers of 2.7%, 1.6% and 8.3%, respectively, compared to 2020. Increased load was driven by an increase in heating degree days of 3.1% and an increase in retail customers of 1.0% compared to 2020.

•Decoupling revenue decreased $1.2 million, primarily attributable to increased usage in the current period compared to the same period in 2020, as noted above in the retail revenue section. This resulted in allowed natural gas revenues being closer to actual natural gas revenues in the current period, whereas in the same period in 2020, allowed revenues were much higher than actual revenues.

•Other decoupling revenue increased $1.7 million, due to a decrease in current period amortization of prior year undercollected revenues compared to the same period in 2020. This is attributable to a decrease in amortization rates.

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•Transportation and other revenue decreased $1.8 million primarily due to a decrease in provision for rate refunds of $3.8 million and a decrease in gas rental services revenue of $1.2 million; partially offset by a $2.7 million reduction of entitlement constraint charges incurred against revenue compared to the same period in 2020.

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, 2020 and 2021:

Three Months Ended March 31, 2020 compared to 2021

•Net unrealized (gain) loss on derivative instruments decreased $71.5 million to a net gain of $23.0 million for the quarter ended March 31, 2021. One of the drivers is related to the change in the weighted average forward prices for electric and natural gas. Specifically, electric prices increased 29.1% resulting in a $54.9 million gain for electric. Natural gas prices increased 16.1% resulting in a $23.5 million gain for natural gas. The other driver is related to the net settlements of electric and natural gas trades previously recorded as $5.3 million in losses and $12.2 million in gains, respectively, that settled and are recorded in purchased electricity or electric generation fuel which results in a loss of $6.9 million for unrealized gains and losses on derivative instruments. 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 $5.6 million primarily due to an increase of $3.2 million of uncollectible accounts driven by COVID-19 disconnect suspension, an increase of $1.2 million of customer assistance expense related to the PSE's policies to reduce the impact to customers from COVID-19 and an increase of $1.2 of injuries and damages expense due to a $1.0 million decrease to the loss reserve in the first quarter of 2020; partially offset by a decrease in customer records and collection expense of $1.7 million due to reduced billing, collection, disconnects and field work due to COVID-19.

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•Depreciation and amortization expense increased $50.3 million primarily driven by: (i) Electric amortization increased by $32.5 million or 154.7% from the same period in 2020. This increase is primarily driven by a $21.6 million change in PTC amortization and the completion of amortization period for the regulatory liability with Microsoft power costs in 2020; (ii) Conservation amortization increased by $6.7 million due to an increase in retail usage of 2.7% and 2.5% for electric and natural gas, respectively; (iii) Common amortization increased by $5.8 million or 30.5% from the same period in 2020. The increase is primarily driven by a lower level of depreciation deferred for the GTZ program due to the final 2019 GRC order; (iv) Electric distribution depreciation increased $1.8 million or 4.9% from the same period in 2020. The increase is primarily due to $211.4 million in net additions of electric distribution assets; and (v) Natural gas amortization increased by $2.4 million or 134% from the same period in 2020. The increase is primarily driven by the final accounting for the AMI deferrals provided by the results of the 2019 GRC and net additions primarily of natural gas intangible utility plant of $25.9 million.

•Taxes other than income taxes increased $4.8 million primarily due to an increase of $2.2 million related to the electric state excise tax and $1.3 million related to electric municipal taxes driven by the increase in retail revenue in 2021 as compared to 2020.

Income Tax Expense    

•Income tax expense increased $3.4 million primarily driven by an increase in pre-tax book income and was partially offset by the amortization of excess deferred income taxes (EDIT) which also contributed to a decline in the effective tax rate.

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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, 2020 and 2021, is as follows:

Three Months Ended March 31, 2020 compared to 2021

Summary Results of Operation

Puget Energy’s net income increased for the three months ended March 31, 2021 by $94.1 million when compared to the same period in the prior year. The increase is primarily due to increased PSE net income and decreased Puget Energy income tax expense as Puget Energy's effective tax rate decreased due to the amortization of unprotected EDIT.

Capital Requirements

Contractual Obligations and Commercial Commitments

In addition 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, 2020, during the three months ended March 31, 2021, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $777.4 million through 2037.

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, 2020.

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The following are the Company's aggregate availability under commercial commitments as of March 31, 2021:

Puget Energy and Puget Sound Energy	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total		2021		2022-2023		2024-2025		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	776,500		—		776,500		—		—
Less: Inter-company short-term debt elimination	(30,000)		—		—		—		(30,000)
Total Puget Energy commercial commitments	$	1,576,500	$	—	$	1,576,500	$	—	$	—

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

Off-Balance Sheet Arrangements

As of March 31, 2021, 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.  Due to business disruptions caused by the COVID-19 pandemic, the Company closely monitored and adjusted capital expenditures, resulting in a decrease of $17.7 million compared to forecasted amounts for the three months ended March 31, 2021.  Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $213.8 million for the three months ended March 31, 2021. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Millions)	2021	2022	2023
Total energy delivery, technology and facilities expenditures	$953.9	$974.4	$1,135.1

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.  

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Capital Resources

Cash from Operations

Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		Change
Net income	$	199,470	$	111,321	$	88,149
Non-cash items1	190,391		215,063		(24,672)
Changes in cash flow resulting from working capital2	876		24,754		(23,878)
Regulatory assets and liabilities	(14,351)		(16,865)		2,514
Purchased gas adjustment	40,868		41,429		(561)
Other non-current assets and liabilities3	(3,077)		(23,801)		20,724
Net cash provided by operating activities	$	414,177	$	351,901	$	62,276

_______________

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, 2021 compared to 2020

Cash generated from operations for the three months ended March 31, 2021 increased by $62.3 million including a net income increase of $88.1 million. The following are significant factors that impacted PSE's cash flows from operations:

•Cash flow adjustments resulting from non-cash items decreased $24.7 million primarily due to a $71.5 million change from a net unrealized loss on derivative instruments of $48.5 million to a net unrealized gain on derivative instruments of $23.0 million, a $21.6 million change in PTC utilization, offset by increases in depreciation and amortization of $43.6 million, amortization of TCJA Over Collection of $10.0 million, conservation amortization of $6.7 million, deferred income taxes of $8.8 million. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.

•Cash flows resulting from changes in working capital decreased $23.9 million. As a result of the COVID-19 pandemic and its impact on the economy, along with our initiative to suspend disconnections of customers for non-payment, cash outflow in Accounts Receivable increased $43.8 million. The increase of cash outflow in Account Receivable was partially offset by $21.3 million increase of cash inflow in Account Payable.

•Cash flow resulting from purchased gas adjustment (long-term) increased $0.6 million.

•Cash flows resulting from regulatory assets and liabilities increased $2.5 million primarily due to a $15.9 million increase in the power cost adjustment mechanism, partially offset by a deferral of $12.9 million of 2021 storm excess costs.

•Cash flow resulting from changes in other non-current assets and liabilities increased $20.7 million primarily due to payments made in both SERP liability and LTIP (Long-Term Incentive Plan) liability in 2020 were higher comparing to 2021.

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Puget Energy	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		Change
Net income	$	(10,477)	$	(16,385)	$	5,908
Non-cash items1	(11,720)		(932)		(10,788)
Changes in cash flow resulting from working capital2	(5,913)		(19,998)		14,085
Other non-current assets and liabilities3	(2,618)		(3,215)		597
Net cash provided by operating activities	$	(30,728)	$	(40,530)	$	9,802

_______________

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, 2021 compared to 2020

Cash generated from operations for the three months ended March 31, 2021, in addition to the changes discussed at PSE above, increased by $9.8 million compared to the same period in 2020, which includes a net income increase of $5.9 million.  The remaining change was primarily impacted by the factors explained below:

•Non-cash items decreased $10.8 million due to changes in deferred taxes.

•Cash flow resulting from working capital increased $14.1 million primarily due to a $9.0 million increase caused by the change of eliminations of PSE's intercompany account receivable and account payable balances with Puget LNG and Puget Energy, an increase in tax payable of $5.6 million, partially offset by other accrued expenses.

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. S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome and Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. Subsequently, S&P removed Puget Energy and PSE from CreditWatch negative. All three credit agencies indicated that continued stress on credit metrics and/or lack of sufficient regulatory rate relief over the relative near term could result in additional negative ratings implications, including a credit rating downgrade. A consistent credit rating downgrade by the three credit agencies would lower Puget Energy from investment grade to non-investment grade, however, PSE would remain at investment grade, assuming a one notch credit adjustment. Additionally, a credit rating downgrade would increase the cost of borrowing for Puget Energy and PSE in future long-term financings and impact the terms under their existing credit facilities. Any increase in the cost of borrowing would 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. 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

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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.

Commercial paper markets were significantly impacted for the period of January 1, 2020 to June 30, 2020, due to COVID-19, which limited commercial paper borrowings so therefore the Company drew short term funding from its credit facility. The Company created a minimum cash reserve of $100 million on April 1, 2020, which was intended to be utilized to cover cash disbursements in the event of illiquid markets. As a result of significantly improved commercial paper markets and steady cash collection over the second quarter of 2020, the Company reduced its cash reserve requirement to $10 - $15 million. Evolving factors that we cannot accurately predict, including the duration and scope of the COVID-19 pandemic, and any relevant governmental, business and customers’ actions that have been and continue to be taken in response to the COVID-19 pandemic, could negatively impact the Company’s liquidity.

Puget Sound Energy

Credit Facility

As of March 31, 2021, 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 financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of March 31, 2021, 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, 2021, no amount was drawn under PSE's credit facility and $191.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.7 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

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, 2021, 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, 2021, PSE could issue:

•Approximately $2.1 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $3.5 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, 2021; and

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•Approximately $824.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.4 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, 2021.

At March 31, 2021, PSE had approximately $8.0 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations

On August 2, 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, $550.0 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, 2021, approximately $1.2 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 49.9% at March 31, 2021, and the EBITDA to interest expense was 5.4 to 1.0 for the twelve months ended March 31, 2021.

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, 2021, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Long Term Debt

The Company had no new long-term debt activities in the three months ended March 31, 2021. 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 10K for the year ended December 31, 2020.

Puget Energy

Credit Facility

At March 31, 2021, Puget Energy maintained an $800.0 million credit facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion. The unsecured 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, 2021, there was $23.5 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 agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of March 31, 2021, Puget Energy was in compliance with all applicable covenants.

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Long-Term Debt

The Company had no new long-term debt activities in the three months ended March 31, 2021. The Company is evaluating refinancing options related to $500 million of senior secured notes that mature in September 2021. The Company will monitor interest rate dynamics over the next several months, and evaluate various term structures and timing of when to refinance the senior secured notes. 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 10K for the year ended December 31, 2020.

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  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 3.6 to 1.0 for the twelve months ended March 31, 2021.

At March 31, 2021, 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 100 Percent Clean Electric Bill that supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The Clean Energy Transformation Act 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 each IOU must propose interim targets for meeting the 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend 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 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 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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and the operator of Colstrip, Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation

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increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The 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 the year 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 undepreciated investment and to allow in electric rates all prudently incurred decommissioning, and remediation costs associated with the facilities. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this proposed agreement, PSE would have retained its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's ownership. The proposed agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE had agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval.

On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. However, after evaluating the likelihood of the regulatory approval process in both Washington and Montana, on October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and the proposed power purchase agreement and relieve all claims against one another arising out of or relating to the sale agreement. The termination of the proposed sale and proposed PPA resulted in the withdrawal of PSE's filing with the Washington Commission. As such, Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet.

Regional Haze Rule

In January 2017, the U.S. Environmental Protection Agency (EPA) published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the D.C. Circuit, pending resolution of EPA's reconsideration of the rule.

Clean Air Act 111(d)/EPA Clean Power Plan

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule.

In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act, as a replacement to the CPP rule. The ACE rule, along with the repeal of the CPP rule, were finalized in June 2019, and establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. On January 19, 2021 the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE rule and remanded the record back to the Agency for further consideration consistent with its opinion, finding that the rule misinterpreted the Clean Air Act. PSE is evaluating this vacatur to determine impact on operations.

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Washington Clean Air Rule

The Washington clean air rule (CAR) was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Superior Court of the State of Washington for Thurston County. In March 2018, the Superior Court of the State of Washington for Thurston County invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. The Washington State Department of Ecology and the four parties asked Thurston County to stay this case until the 2020 Washington State legislative session concluded and now the Washington State Department of Ecology plans to ask the court to extend the stay until the COVID-19 pandemic is over. Meanwhile, the four companies moved to voluntarily dismiss the federal court litigation without prejudice in March 2020.

Related Party Transactions

In August 2015, PSE filed a proposal with the Washington Commission to develop a liquified 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.

The Tacoma LNG facility achieved mechanical completion in February 2021. 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, $239.4 million of construction work in progress and $0.2 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 expense and other" financial statement line items, respectively, as of March 31, 2021. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.

IBEW Union Contract

The International Brotherhood of Electrical Workers (IBEW) Local 77 union and PSE reached an agreement on a new contract, which was ratified on March 26, 2020, upon the IBEW vote approving the provisions and took effect on April 1, 2020. The contract is for six years and will expire March 31, 2026.

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.

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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, 2020.

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.

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, 2021, 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, 2021 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

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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, 2021, 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, 2021 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

PART II            OTHER INFORMATION

Item 1.         Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of March 31, 2021.  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.

On August 26, 2020, the SEC issued Final Rule Release No. 33-10825, "Modernization of Regulation S-K Items 101, 103, and 105." This rule, which became effective on November 9, 2020, updated the disclosure threshold for environmental proceedings. Prior to this rule, environmental proceedings to which the government is a party were required to be disclosed if the proceeding was expected to result in sanctions of $100,000 or more. The above referenced rule increases the quantitative threshold to $300,000, but also permits the registrant to elect a higher threshold, limited to the lesser of $1 million or 1% of consolidated current assets, if the registrant determines that such threshold is more reasonably designed to result in the disclosure of material environmental proceedings. The registrant must disclose this alternative threshold in each annual and quarterly report.

Given the size of the Company's operations, we have elected to adopt a threshold of $1 million. 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 period ended December 31, 2020.

Item 6.         Exhibits

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

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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 dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
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, 2021 filed on May 05, 2021 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).

__________________

* Filed herewith.

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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 5, 2021

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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 5, 2021
/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, Daniel A. Doyle, 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 5, 2021
/s/ Daniel A. Doyle
Daniel A. Doyle
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 5, 2021
/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, Daniel A. Doyle, 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 5, 2021
/s/ Daniel A. Doyle
Daniel A. Doyle
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, 2021 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-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-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	May 5, 2021
/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 theperiod ended March 31, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Daniel A. Doyle, 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-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

Date:	May 5, 2021
/s/ Daniel A. Doyle
Daniel A. Doyle
Senior Vice President and Chief Financial Officer

XML

Document And Entity Information	3 Months Ended
	Mar. 31, 2021 shares
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2021
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Transition Report	false
Document Quarterly Report	true
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-13
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2021
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Transition Report	false
Document Quarterly Report	true

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating revenue:
Electric	$ 758,592	$ 669,090
Natural Gas	392,906	371,031
Other	8,588	6,009
Total operating revenue	1,160,086	1,046,130
Energy costs:
Purchased electricity	205,410	165,742
Electric generation fuel	60,418	63,624
Residential exchange	(25,802)	(24,634)
Purchased natural gas	155,015	154,876
Unrealized (gain) loss on derivative instruments, net	(23,002)	48,541
Utility operations and maintenance	160,540	154,922
Non-utility expense and other	9,906	12,962
Depreciation & Amortization	208,431	164,816
Conservation amortization	34,060	27,393
Taxes other than income taxes	110,310	105,504
Total operating expenses	895,286	873,746
Operating income (loss)	264,800	172,384
Other income (expense):
Other income	13,630	14,059
Other expense	(1,510)	(2,282)
Interest charges:
AFUDC	3,586	3,643
Interest expense	(89,360)	(88,884)
Income (loss) before income taxes	191,146	98,920
Income tax (benefit) expense	2,153	3,984
Net income (loss)	188,993	94,936
Subsidiaries [Member]
Operating revenue:
Electric	758,592	669,090
Natural Gas	392,906	371,031
Other	8,588	6,009
Total operating revenue	1,160,086	1,046,130
Energy costs:
Purchased electricity	205,410	165,742
Electric generation fuel	60,418	63,624
Residential exchange	(25,802)	(24,634)
Purchased natural gas	155,015	154,876
Unrealized (gain) loss on derivative instruments, net	(23,002)	48,541
Utility operations and maintenance	160,540	154,922
Non-utility expense and other	9,418	12,735
Depreciation & Amortization	208,362	164,771
Conservation amortization	34,060	27,393
Taxes other than income taxes	110,310	105,504
Total operating expenses	894,729	873,474
Operating income (loss)	265,357	172,656
Other income (expense):
Other income	11,034	11,283
Other expense	(1,510)	(2,282)
Interest charges:
AFUDC	3,586	3,643
Interest expense	(62,371)	(60,714)
Income (loss) before income taxes	216,096	124,586
Income tax (benefit) expense	16,626	13,265
Net income (loss)	$ 199,470	$ 111,321

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net Income (Loss) Attributable to Parent	$ 188,993	$ 94,936
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,385	5,170
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent, Total	2,385	5,170
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total	191,378	100,106
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	199,470	111,321
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent [Abstract]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	4,458	7,710
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	96	96
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent, Total	4,554	7,806
Comprehensive Income (Loss), Net of Tax, Attributable to Parent, Total	$ 204,024	$ 119,127

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 634	$ 1,373
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,185	2,047
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 26

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Utility Plant [Abstract]
Public Utilities Property Plant And Equipment Electric Plant	$ 9,288,156	$ 9,200,231
Public Utilities Property Plant And Equipment Gas Plant	4,296,864	4,227,532
Public Utilities Property Plant And Equipment Common Plant	1,085,442	1,116,524
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(3,736,675)	(3,671,094)
Public Utilities, Property, Plant and Equipment, Net, Total	10,933,787	10,873,193
Other Property And Investments [Abstract]
Goodwill	1,656,513	1,656,513
Other Property And Investments	327,674	324,184
Total Other Property And Investments	1,984,187	1,980,697
Assets, Current [Abstract]
Cash and Cash Equivalents, at Carrying Value	36,507	52,307
Restricted Cash and Cash Equivalents, Current	24,443	29,544
Accounts Receivable, after Allowance for Credit Loss, Current	374,296	352,132
Unbilled Revenues	219,450	221,871
Other Inventory, Supplies, Gross	117,891	118,333
Fuel And Gas Inventory At Average Cost	38,743	48,795
Derivative Asset, Current	47,221	33,015
Prepaid Expense and Other Assets, Current	49,630	45,746
Power Contract Acquisition Adjustment Gain Current	15,694	14,874
Assets, Current, Total	923,875	916,617
Other Longterm And Regulatory Assets [Abstract]
Power Cost Adjustment Mechanism Asset, Noncurrent	71,257	82,801
purchase gas adjustment, long-term	46,787	87,655
Regulatory Assets Related To Power Contracts	11,398	11,728
Other Regulatory Assets	737,377	747,651
Derivative Asset, Noncurrent	4,925	8,805
Power Contract Acquisition Adjustment Non Current	75,601	80,900
Operating Lease, Right-of-Use Asset	194,245	172,167
Other Assets, Noncurrent	86,680	80,751
Total Longterm And Regulatory Assets	1,228,270	1,272,458
Assets, Total	15,070,119	15,042,965
Capitalization [Abstract]
Common stock	0	0
Additional Paid in Capital	3,313,532	3,313,532
Retained Earnings (Accumulated Deficit)	1,078,841	912,787
Accumulated Other Comprehensive Income (Loss), Net of Tax	(84,052)	(86,437)
Stockholders' Equity Attributable to Parent, Total	4,308,321	4,139,882
Long-term Debt, Excluding Current Maturities [Abstract]
Senior Notes, Noncurrent	4,212,000	4,212,000
Long-term Pollution Control Bond	161,860	161,860
Other Long-term Debt, Noncurrent	1,733,500	1,724,700
Debt discount and other	(203,026)	(206,120)
Long-term Debt, Excluding Current Maturities, Total	5,904,334	5,892,440
Capitalization, Long-term Debt and Equity, Total	10,212,655	10,032,322
Liabilities, Current [Abstract]
Accounts Payable, Current	324,037	342,404
Short-term Debt	191,000	373,800
Long-term Debt, Current Maturities	526,345	526,412
Accrued Expenses [Abstract]
Taxes Payable, Current	134,228	110,752
Employee-related Liabilities, Current	35,295	42,530
Interest Payable, Current	79,400	73,647
Derivative Liability, Current	19,839	31,441
Power Contract Acquisition Adjustment Loss Current	2,036	2,039
Operating Lease, Liability, Current	19,238	19,204
Other Liabilities, Current	88,335	73,385
Liabilities, Current, Total	1,419,753	1,595,614
Longterm And Regulatory Liabilities [Abstract]
Deferred Tax and Other Liabilities, Noncurrent	846,692	810,729
Derivative Liability, Noncurrent	24,332	29,833
Regulatory Liabilities, Noncurrent	735,368	732,498
Deferred Tax Liabilities, Regulatory Assets and Liabilities	924,567	953,274
Regulatory Liabilities Related To Power Contracts	91,295	95,774
Power Contract Acquisition Adjustment Loss Non Current	9,362	9,689
Operating Lease, Liability, Noncurrent	182,288	160,980
Other Deferred Credits	623,807	622,252
Total Longterm And Regulatory Liabilities	3,437,711	3,415,029
Commitments and Contingencies
Liabilities and Equity, Total	$ 15,070,119	15,042,965
Common stock, par value (in dollars per share)	$ 0.01
Common stock, shares authorized (in shares)	1,000
Common Stock, Shares, Outstanding	200
Subsidiaries [Member]
Utility Plant [Abstract]
Public Utilities Property Plant And Equipment Electric Plant	$ 11,116,750	11,035,402
Public Utilities Property Plant And Equipment Gas Plant	4,855,247	4,786,419
Public Utilities Property Plant And Equipment Common Plant	1,107,719	1,139,120
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(6,145,929)	(6,087,748)
Public Utilities, Property, Plant and Equipment, Net, Total	10,933,787	10,873,193
Other Property And Investments [Abstract]
Other Property And Investments	83,620	83,855
Total Other Property And Investments	83,620	83,855
Assets, Current [Abstract]
Cash and Cash Equivalents, at Carrying Value	36,051	51,177
Restricted Cash and Cash Equivalents, Current	24,443	29,544
Accounts Receivable, after Allowance for Credit Loss, Current	376,228	355,850
Unbilled Revenues	219,450	221,871
Other Inventory, Supplies, Gross	117,891	118,333
Fuel And Gas Inventory At Average Cost	37,479	47,531
Derivative Asset, Current	47,221	33,015
Prepaid Expense and Other Assets, Current	49,630	45,746
Assets, Current, Total	908,393	903,067
Other Longterm And Regulatory Assets [Abstract]
Power Cost Adjustment Mechanism Asset, Noncurrent	71,257	82,801
purchase gas adjustment, long-term	46,787	87,655
Other Regulatory Assets	737,377	747,651
Derivative Asset, Noncurrent	4,925	8,805
Operating Lease, Right-of-Use Asset	194,245	172,167
Other Assets, Noncurrent	85,294	79,231
Total Longterm And Regulatory Assets	1,139,885	1,178,310
Assets, Total	13,065,685	13,038,425
Capitalization [Abstract]
Common stock	859	859
Additional Paid in Capital	3,485,105	3,485,105
Retained Earnings (Accumulated Deficit)	1,023,818	876,401
Accumulated Other Comprehensive Income (Loss), Net of Tax	(176,402)	(180,956)
Stockholders' Equity Attributable to Parent, Total	4,333,380	4,181,409
Long-term Debt, Excluding Current Maturities [Abstract]
Senior Notes, Noncurrent	4,212,000	4,212,000
Long-term Pollution Control Bond	161,860	161,860
Debt discount and other	(35,337)	(35,816)
Long-term Debt, Excluding Current Maturities, Total	4,338,523	4,338,044
Capitalization, Long-term Debt and Equity, Total	8,671,903	8,519,453
Liabilities, Current [Abstract]
Accounts Payable, Current	324,152	342,504
Short-term Debt	191,000	373,800
Long-term Debt, Current Maturities	2,345	2,412
Accrued Expenses [Abstract]
Taxes Payable, Current	130,781	107,254
Employee-related Liabilities, Current	35,295	42,530
Interest Payable, Current	58,002	48,189
Derivative Liability, Current	19,839	31,441
Operating Lease, Liability, Current	19,238	19,204
Other Liabilities, Current	88,335	73,385
Liabilities, Current, Total	868,987	1,040,719
Longterm And Regulatory Liabilities [Abstract]
Deferred Tax and Other Liabilities, Noncurrent	1,038,347	987,382
Derivative Liability, Noncurrent	24,332	29,833
Regulatory Liabilities, Noncurrent	734,104	731,234
Deferred Tax Liabilities, Regulatory Assets and Liabilities	925,277	953,987
Operating Lease, Liability, Noncurrent	182,288	160,980
Other Deferred Credits	620,447	614,837
Total Longterm And Regulatory Liabilities	3,524,795	3,478,253
Commitments and Contingencies
Liabilities and Equity, Total	$ 13,065,685	$ 13,038,425
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 BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
ASSETS
Construction work in progress	$ 749,572	$ 712,204
Assets, Current [Abstract]
Allowance for doubtful accounts	30,392	20,080
Common shareholder’s equity:
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	749,572	712,204
Allowance for doubtful accounts	$ 30,392	20,080
Common stock, par value (in dollars per share)	$ 0.01
Common stock, shares authorized (in shares)	1,000
Common Stock, Shares, Outstanding	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 749,572	712,204
Assets, Current [Abstract]
Allowance for doubtful accounts	30,392	20,080
Common shareholder’s equity:
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	749,572	712,204
Allowance for doubtful accounts	$ 30,392	$ 20,080
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, 2019		200					85,903,791
Beginning Balance at Dec. 31, 2019	$ 4,000,299	$ 0	$ 3,308,957	$ 775,491	$ (84,149)	$ 4,048,680	$ 859	$ 3,485,105	$ 751,193	$ (188,477)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss) Attributable to Parent	94,936			94,936		111,321			111,321
Dividends, Common Stock	(22,645)			(22,645)		(53,794)			(53,794)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	5,170				5,170	7,806				7,806
Ending Balance (in shares) at Mar. 31, 2020		200					85,903,791
Ending Balance at Mar. 31, 2020	4,077,760	$ 0	3,308,957	847,782	(78,979)	$ 4,114,013	$ 859	3,485,105	808,720	(180,671)
Beginning Balance (in shares) at Dec. 31, 2020		200				85,903,791	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	200				85,903,791	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)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	$ 188,993	$ 94,936
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation & Amortization	208,431	164,816
Conservation amortization	34,060	27,393
Deferred Income Taxes and Tax Credits	6,622	8,602
Unrealized Gain (Loss) on Derivatives	(23,002)	48,541
Afudc Equity	(5,780)	(5,603)
Monetized production tax credits	(45,178)	(23,543)
Other Noncash Income (Expense)	3,518	(6,075)
Increase (Decrease) in Other Regulatory Assets	(14,351)	(16,865)
Purchased gas adjustment	40,868	41,429
Increase (Decrease) in Other Operating Assets	(5,695)	(27,016)
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Accounts and Other Receivables	(19,743)	24,120
Increase (Decrease) in Materials and Supplies	442	1,072
Increase (Decrease) in Fuel Inventories	10,052	14,497
Increase (Decrease) in Prepaid Expense and Other Assets	(3,884)	251
Increase (Decrease) in Accounts Payable	(14,868)	(45,236)
Increase (Decrease) in Income Taxes Payable	23,476	21,178
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(512)	(11,126)
Net Cash Provided by (Used in) Operating Activities, Total	383,449	311,371
Net Cash Provided by (Used in) Investing Activities [Abstract]
Construction expenditures excluding equity allowance for funds used during construction	(213,781)	(223,707)
Payments for (Proceeds from) Other Investing Activities	362	(233)
Net Cash Provided by (Used in) Investing Activities, Total	(213,419)	(223,940)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from (Repayments of) Short-term Debt	(182,800)	(100,000)
Payments of Dividends	(22,939)	(22,645)
Proceeds from Issuance of Long-term Debt	8,800	7,400
Repayments of Long-term Debt	(66)	0
Proceeds from (Payments for) Other Financing Activities	6,074	3,670
Net Cash Provided by (Used in) Financing Activities, Total	(190,931)	(111,575)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	(20,901)	(24,144)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	81,851	66,146	$ 66,146
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	60,950	42,002	81,851
Supplemental Cash Flow Information [Abstract]
Interest Paid, Excluding Capitalized Interest, Operating Activities	77,160	78,636
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Capital Expenditures Incurred but Not yet Paid	54,805	56,699
Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	199,470	111,321
Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract]
Depreciation & Amortization	208,362	164,771
Conservation amortization	34,060	27,393
Deferred Income Taxes and Tax Credits	21,044	12,215
Unrealized Gain (Loss) on Derivatives	(23,002)	48,541
Afudc Equity	(5,780)	(5,603)
Monetized production tax credits	(45,178)	(23,543)
Other Noncash Income (Expense)	885	(8,711)
Increase (Decrease) in Other Regulatory Assets	(14,351)	(16,865)
Purchased gas adjustment	40,868	41,429
Increase (Decrease) in Other Operating Assets	(3,077)	(23,801)
Increase (Decrease) in Operating Capital [Abstract]
Increase (Decrease) in Accounts and Other Receivables	(17,957)	25,892
Increase (Decrease) in Materials and Supplies	442	1,072
Increase (Decrease) in Fuel Inventories	10,052	14,497
Increase (Decrease) in Prepaid Expense and Other Assets	(3,884)	251
Increase (Decrease) in Accounts Payable	(14,853)	(36,201)
Increase (Decrease) in Income Taxes Payable	23,527	26,850
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	3,549	(7,607)
Net Cash Provided by (Used in) Operating Activities, Total	414,177	351,901
Net Cash Provided by (Used in) Investing Activities [Abstract]
Construction expenditures excluding equity allowance for funds used during construction	(205,927)	(225,612)
Payments for (Proceeds from) Other Investing Activities	362	(233)
Net Cash Provided by (Used in) Investing Activities, Total	(205,565)	(225,845)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from (Repayments of) Short-term Debt	(182,800)	(100,000)
Payments of Dividends	(52,053)	(53,794)
Repayments of Long-term Debt	(66)	0
Proceeds from (Payments for) Other Financing Activities	6,080	3,668
Net Cash Provided by (Used in) Financing Activities, Total	(228,839)	(150,126)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	(20,227)	(24,070)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	80,721	64,891	64,891
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	60,494	40,821	$ 80,721
Supplemental Cash Flow Information [Abstract]
Interest Paid, Excluding Capitalized Interest, Operating Activities	47,749	47,115
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 54,805	$ 56,699

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Summary of Consolidation and Significant Accounting Policy

3 Months Ended

Mar. 31, 2021

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 Puget Sound Energy. 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, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. 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 FASB 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. 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, 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 2020 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 governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment.

The following table presents the activity in the allowance for credit losses for accounts receivable for the three months ended March 31, 2021 and 2020:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020
Allowance for credit losses:
Beginning balance	$	20,080	$	8,294
Provision for credit loss expense	12,452		4,894
Receivables charged-off	(2,140)		(3,374)
Total ending allowance balance	$	30,392	$	9,814

Tacoma LNG Facility

In August 2015, PSE filed a proposal with the Washington Commission to develop a liquified natural gas (LNG) facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. A meeting with the Washington Pollution Control Hearings Board occurred in April 2021 and a decision is forthcoming. The facility achieved mechanical completion in February 2021, however, it remains nonoperational as additional construction and testing are completed.

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, $239.4 million and $231.6 million of 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, 2021 and December 31, 2020, respectively. Additionally, $0.2 million and $0.3 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, 2021, and March 31, 2020, respectively. Additionally, $216.5 million and $207.7 million of 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, 2021 and December 31, 2020, 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 $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income and $3.6 million is included in accounts payable on the Company's consolidated balance sheet for the quarter ended March 31, 2021.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2021

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Reference Rate Reform

In March 2020, the FASB issued 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 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, 2021, 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.

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Revenue

3 Months Ended

Mar. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31,
Revenue from contracts with customers:	2021		2020
Electric retail	$	664,102	$	607,693
Natural gas retail	387,863		365,637
Other	56,129		43,774
Total revenue from contracts with customers	1,108,094		1,017,104
Alternative revenue programs	(1,928)		1,150
Other non-customer revenue	53,920		27,876
Total operating revenue	$	1,160,086	$	1,046,130

Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services.

Electric and Natural Gas Retail Revenue

Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis.

Electric Transmission and Natural Gas Transportation Revenue

Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.

Biogas

Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.

Wholesale

Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser.

Other Revenue

In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance.

Transaction Price Allocated to Remaining Performance Obligations

In December 2020, PLNG entered into a contract with one customer where PLNG 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) fluctuating 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.

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Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2021

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 of 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, 2021					December 31, 2020
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	32,366	$	33,743	*	$	22,544	$	46,922
Natural gas derivatives (MMBtus)3	331	19,780		10,428		320	19,276		14,352
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274
Current		$	47,221	$	19,839		$	33,015	$	31,441
Long-term		4,925		24,332			8,805		29,833
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274

_______________

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 purchased gas adjustment (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 221.4 million One Million British Thermal Units (MMBtu) and purchased electricity of

4.4 million Megawatt Hours (MWhs) at March 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020.

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, 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	$	52,146	$	—	$	52,146	$	(21,105)	$	—	$	31,041
Liabilities:
Energy derivative contracts	$	44,171	$	—	$	44,171	$	(21,105)	$	(143)	$	22,923

Puget Energy and Puget Sound Energy	At December 31, 2020
	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	$	41,820	$	—	$	41,820	$	(21,696)	$	—	$	20,124
Liabilities:
Energy derivative contracts	$	61,274	$	—	$	61,274	$	(21,696)	$	(9,343)	$	30,235

_______________

1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting 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	2021		2020
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	1,628	$	(9,755)
Realized	Electric generation fuel	8,313		1,296
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	21,374		(38,786)
Realized	Purchased electricity	(13,303)		(5,935)
Total gain (loss) recognized in income on derivatives		$	18,012	$	(53,180)

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, 2021, approximately 99.2% 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 0.8% 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 NGX exchange 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, 2021, PSE had cash posted as collateral of $3.2 million related to contracts executed on the ICE platform. Also, as of March 31, 2021, PSE had $12.0 million in cash posted as collateral and a $1.0 million 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, 2021.

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, 2021						At December 31, 2020
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	21,991	$	—	$	21,991	$	26,966	$	—	$	26,966
Requested credit for adequate assurance	7,330		—		—		6,576		—		—
Forward value of contract3	143		11,990		N/A		9,343		20,903		N/A
Total	$	29,464	$	11,990	$	21,991	$	42,885	$	20,903	$	26,966

_______________

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.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2021

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 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 $52.0 million and $52.7 million at March 31, 2021 and December 31, 2020 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, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	5,670,834	$	7,063,347	$	5,667,740	$	7,755,946
Long-term debt (variable-rate)	2	233,500		233,500		224,700		224,700
Total liabilities		$	5,904,334	$	7,296,847	$	5,892,440	$	7,980,646

Puget Sound Energy		March 31, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358
Total liabilities		$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358

_______________

1 The carrying value includes debt issuances costs of $21.9 million and $22.7 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.6 million and $22.9 million for March 31, 2021 and December 31, 2020, 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. 2021						Fair Value At December 31, 2020
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	31,980	$	386	$	32,366	$	21,947	$	597	$	22,544
Natural gas derivative instruments	19,677		103		19,780		19,139		137		19,276
Total assets	$	51,657	$	489	$	52,146	$	41,086	$	734	$	41,820
Liabilities:
Electric derivative instruments	$	12,187	$	21,556	$	33,743	$	22,607	$	24,315	$	46,922
Natural gas derivative instruments	8,491		1,937		10,428		13,080		1,272		14,352
Total liabilities	$	20,678	$	23,493	$	44,171	$	35,687	$	25,587	$	61,274

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)	2021						2020
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	820		—		820		(24,552)		—		(24,552)
Included in regulatory assets / liabilities	—		(888)		(888)		—		323		323
Settlements	1,728		189		1,917		1,626		(513)		1,113
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		—		—		—
Balance at end of period	$	(21,170)	$	(1,834)	$	(23,004)	$	(26,305)	$	1,092	$	(25,213)

_______________

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 $0.8 million and zero for three months ended March 31, 2021 and 2020, 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, 2021

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	386	$	21,556	Discounted cash flow	Power prices (per MWh)	$	22.87	$	44.21	$	32.56
Natural gas	$	103	$	1,937	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.10	$	3.57	$	2.70

_______________

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, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	597	$	24,315	Discounted cash flow	Power prices (per MWh)	$	22.82	$	41.66	$	31.54
Natural gas	$	137	$	1,272	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.89	$	3.42	$	2.47

___________

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, 2021, and December 31, 2020, 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 $4.9 million and $5.5 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, 2021, 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".

The following table presents the impairment recorded to the Company's intangible asset contracts in 2020, with corresponding reductions to the regulatory liability:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value	Fair Value	Write Down
March 31, 2020	Rocky Reach	$147,168	$94,603	$52,565

The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. The unobservable input averages disclosed below represent the arithmetic average of the inputs and are not weighted by volume. A less significant input is the discount rate reflective of a market participant's cost of capital used in the valuation.

The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase

contracts' fair value:

Puget Energy
Valuation Date	Unobservable Input	Low	High	Average
March 31, 2020	Power prices (per MWh)	$10.23	$29.05	$20.88
	Power contract costs per quarter (in thousands)	$6,308	$7,085	$6,468

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Retirement Benefits

3 Months Ended

Mar. 31, 2021

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.  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.  Starting January 1, 2014, all the United Association of Plumbers and Pipefitters (UA) represented employees receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014, for employees represented by the International Brotherhood of Electrical Workers Union (IBEW), participants receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited 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 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. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries.

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.

In 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.

The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2021 and 2020:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,502)		—		—		(91)		(97)
Amortization of prior service cost	(476)		(495)		87		87		2		—
Amortization of net loss (gain)	2,830		1,981		587		586		(10)		(22)
Net periodic benefit cost	$	2,562	$	1,279	$	1,082	$	1,279	$	19	$	21

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,504)		—		—		(91)		(97)
Amortization of prior service cost	(378)		(393)		87		87		2		—
Amortization of net loss (gain)	5,311		4,656		635		659		(15)		(36)
Net periodic benefit cost	$	5,141	$	4,054	$	1,130	$	1,352	$	14	$	7

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2021 and December 31, 2020:

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, 2021		December 31, 2020		March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
Change in benefit obligation:
Benefit obligation at beginning of period	$	849,383	$	774,305	$	46,742	$	63,000	$	12,114	$	11,627
Amendments	—		—		—		—		—		44
Service cost	6,711		24,337		115		756		41		190
Interest cost	5,578		25,180		293		1,464		77		368
Curtailment Loss / (Gain)	—		—		—		—		—		—
Actuarial loss (gain)	—		69,413		—		3,663		—		604
Benefits paid	(11,625)		(42,775)		(496)		(22,141)		(237)		(906)
Medicare part D subsidy received	—		—		—		—		196		187
Administrative Expense	—		(1,077)		—		—		—		—
Benefit obligation at end of period	$	850,047	$	849,383	$	46,654	$	46,742	$	12,191	$	12,114

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, 2021, are expected to be at least $18.0 million, $6.8 million and $0.3 million, respectively. During the three months ended March 31, 2021, the Company contributed $0.5 million to fund the SERP. During the three months ended March 31, 2020, the Company contributed $13.6 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans.

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Regulation and Rates

3 Months Ended

Mar. 31, 2021

Subsidiaries [Member]

Entity Information [Line Items]

Regulation and Rates Disclosure

Regulation and Rates

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, the parties to the PCORC reached a multiparty settlement in principle, with Public Counsel not joining the settlement, but also not opposing. The settlement agreement and supporting testimony was filed with the Washington Commission on April 2, 2021, who held hearings on the matter on April 22, 2021. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1% and, pending approval by the Washington Commission, is expected to be effective June 2021.

General Rate Case

PSE filed a general rate case (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. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes

that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony that included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas, PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

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, which 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%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of depreciation expense associated with PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which 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 $27.7 million, or 1.3%, and the natural gas increase to $0.2 million, or 0.02%.

On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) 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. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is 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 will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling.

Expedited Rate Filing

On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million rate increase for natural

gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.

The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s then-next GRC, filed June 20, 2019, and discussed above:

1)excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019;

2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and

3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.

The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its AMI investment and may defer the return on the AMI investment that was included in the test year of the filing. As noted above, the 2019 GRC effectively ends all deferrals of AMI depreciation expense and deferrals of return on additional AMI investments will be evaluated in future proceedings. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform.  The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas and became effective May 1, 2018, by operation of law.

The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

While the settlement agreement in the ERF provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts through the PSE Schedule 141X tariff, the ongoing treatment of excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences was left to be addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owed to customers will be greater than $0.1 million, PSE would submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021. As this balance was greater than $0.1 million, PSE filed tariff revisions on July 20, 2020 and the Washington Commission approved the filing on August 27, 2020. Finally, the GRC final order determined that PSE is required to pass back 2019 and 2020 protected excess deferred tax reversals totaling $70.8 million over the 12 months following the rate effective period through PSE’s Schedule 141X tariff. The GRC final order also determined that PSE is required to pass back unprotected excess deferred tax balances totaling $38.9 million over 36 months following the rate effective period through PSE’s Schedule 141Z tariff. Further details of the outcome associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.

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. Since 2013, 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 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 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. 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 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

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 as of August 31, 2020 of about $16.0 million for electric delivery and fixed power cost decoupling 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. As part of this filing, PSE will true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing.

On March 31, 2021, 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 $0.9 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; 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, 2021, in its PCA mechanism, PSE under recovered its allowable costs by $11.4 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 $25.1 million for the three months ended March 31, 2020, of which $4.0 million was apportioned to customers and accrued $0.5 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing

On July 1, 2019, 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 effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.

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 2019. 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. Due to concerns about the economic impact of the COVID-19 pandemic on customers, PSE voluntarily, with Washington Commission Staff support, delayed filing an increase to its Schedule 95 rates in its annual PCA report filing in Docket UE-200398, which was approved on July 30, 2020. Subsequently, PSE filed to recover the deferred balance in Docket UE-200893, effective December 1, 2020, and the Washington Commission approved PSE’s request on November 24, 2020. During 2019, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $67.2 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.2 million of the under-recovered amount, and customers were responsible for the remaining $36.0 million, or $37.0 million including interest. As PSE had an approved balance owing from customers including interest at the start of 2019 totaling $4.7 million, the approved cumulative deferral balance for the PCA, as of December 2019, is $41.7 million. As previously stated, this filing is set to collect the customer’s share of the cumulative 2019 imbalance in PSE’s PCA mechanism.

Purchased Gas Adjustment Mechanism

On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020.

On October 24, 2019, the Washington Commission approved PSE’s request for PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the PGA rates effective November 1, 2018; and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events that winter experienced by PSE: the rupture of a pipeline owned by Enbridge, Inc. in October 2018, unusually low temperatures in

February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two-year period, instead of the historic one-year period, from November 2019 through October 2021.

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 the portion of PGA amortization balances originally filed through the annual November 1, 2019 PGA filing under the Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of the originally approved two-year period.

On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.

The following table presents the PGA mechanism balances and activity at March 31, 2021 and December 31, 2020:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2021		2020
PGA receivable beginning balance	$	87,655	$	132,766
Actual natural gas costs	113,175		314,792
Allowed PGA recovery	(154,592)		(363,886)
Interest	549		3,983
PGA receivable ending balance	$	46,787	$	87,655

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. For the period ended March 31, 2021 and December 31, 2020, PSE deferred $4.6 million and $2.8 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% per the 2018 ERF. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and on July 8, 2020, the Washington Commission issued its order in PSE’s 2019 GRC. 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 next GRC. 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 with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is 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 puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. The program ended on September 30, 2020.

On March 28, 2021 the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance for each qualifying low-income household, per program year, with a total program budget of $20.0 million for electric customers and $7.7 million for natural gas customers.

Storm Damage Deferral Accounting

The Washington Commission has defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm 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, 2021, PSE incurred $23.3 million in storm-related electric transmission and distribution system restoration costs, of which $12.9 million and $0.2 million was deferred as regulatory assets related to storms that occurred in 2021 and 2020, respectively. This compares to $9.9 million incurred in storm-related electric transmission and distribution system restoration costs for the three months ended March 31, 2020, of which the Company deferred zero as regulatory assets related to storms that occurred in 2020. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; 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.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2021

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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and the operator of Colstrip, Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The 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 Transition 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 December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would have retained its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's ownership. The proposed agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE had agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval.

On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. However, after evaluating the likelihood of the regulatory approval process in both Washington and Montana, on October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and the proposed power purchase agreement and relieve all claims against one another arising out of or relating to the sale agreement. The termination of the proposed sale and proposed PPA resulted in the withdrawal of PSE's filing with the Washington Commission. Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2020.

Other Commitments and Contingencies

In addition 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, 2020, during the three months ended March 31, 2021, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $777.4 million through 2042.

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 period ended December 31, 2020.

COVID-19

The outbreak of the Coronavirus Disease 2019 (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The full impact on the Company's business from the pandemic, including governmental and regulatory response actions, is unknown at this time and difficult to predict. 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.

Government mandated stay at home orders and private work from home mandates due to COVID-19 have affected electric and gas loads for residential, commercial, and industrial customers. During the quarter ended March 31, 2021, the Company delivered marginally higher electric and decreased natural gas loads of 0.1% and 3.7%, respectively, when comparing weather-adjusted actual to forecast. Decreases in commercial and industrial loads were partially offset by increases in residential loads. Electric retail revenue marginal increases included reduced electric supply costs and the effects of decoupling. The impact on natural gas revenue due to load was offset by gas supply cost and decoupling. The Company anticipates that electric and gas loads will continue to be impacted for the remainder of 2021, due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus.

At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to its customers. The Company has flexibility with capital investments and other measures to maintain sufficient liquidity over the next twelve months. The situation remains fluid and future impacts to the Company that are presently unknown or unanticipated may occur. Furthermore, the severity of impact to the Company could increase the longer the global pandemic persists.

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, 2021, PSE deferred no costs related to this petition specific to COVID-19.

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Leases (Notes)

3 Months Ended

Mar. 31, 2021

Leases [Abstract]

Leases

Leases

Other than the item discussed below, there have been no significant changes regarding the Company's leases as described in Note 9 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million.

Leases

Leases

Other than the item discussed below, there have been no significant changes regarding the Company's leases as described in Note 9 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million.

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Other

3 Months Ended

Mar. 31, 2021

Other [Abstract]

Other

Other

Long-Term Debt

As of March 31, 2021, Puget Energy maintained an $800.0 million credit facility, of which $23.5 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 10K for the year ended December 31, 2020.

Short-term Debt

Short-Term Debt

As of March 31, 2021, no amount was drawn under PSE's credit facility and $191.0 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 10K for the year ended December 31, 2020.

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Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2021

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, 2021 and 2020:

Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020
Allowance for credit losses:
Beginning balance	$	20,080	$	8,294
Provision for credit loss expense	12,452		4,894
Receivables charged-off	(2,140)		(3,374)
Total ending allowance balance	$	30,392	$	9,814

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Revenue (Tables)

3 Months Ended

Mar. 31, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended March 31,
Revenue from contracts with customers:	2021		2020
Electric retail	$	664,102	$	607,693
Natural gas retail	387,863		365,637
Other	56,129		43,774
Total revenue from contracts with customers	1,108,094		1,017,104
Alternative revenue programs	(1,928)		1,150
Other non-customer revenue	53,920		27,876
Total operating revenue	$	1,160,086	$	1,046,130

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

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Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2021

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, 2021					December 31, 2020
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	32,366	$	33,743	*	$	22,544	$	46,922
Natural gas derivatives (MMBtus)3	331	19,780		10,428		320	19,276		14,352
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274
Current		$	47,221	$	19,839		$	33,015	$	31,441
Long-term		4,925		24,332			8,805		29,833
Total derivative contracts		$	52,146	$	44,171		$	41,820	$	61,274

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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 purchased gas adjustment (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 221.4 million One Million British Thermal Units (MMBtu) and purchased electricity of

4.4 million Megawatt Hours (MWhs) at March 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020.

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, 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	$	52,146	$	—	$	52,146	$	(21,105)	$	—	$	31,041
Liabilities:
Energy derivative contracts	$	44,171	$	—	$	44,171	$	(21,105)	$	(143)	$	22,923

Puget Energy and Puget Sound Energy	At December 31, 2020
	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	$	41,820	$	—	$	41,820	$	(21,696)	$	—	$	20,124
Liabilities:
Energy derivative contracts	$	61,274	$	—	$	61,274	$	(21,696)	$	(9,343)	$	30,235

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1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting 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	2021		2020
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	1,628	$	(9,755)
Realized	Electric generation fuel	8,313		1,296
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	21,374		(38,786)
Realized	Purchased electricity	(13,303)		(5,935)
Total gain (loss) recognized in income on derivatives		$	18,012	$	(53,180)

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, 2021						At December 31, 2020
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	21,991	$	—	$	21,991	$	26,966	$	—	$	26,966
Requested credit for adequate assurance	7,330		—		—		6,576		—		—
Forward value of contract3	143		11,990		N/A		9,343		20,903		N/A
Total	$	29,464	$	11,990	$	21,991	$	42,885	$	20,903	$	26,966

_______________

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.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2021

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, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	5,670,834	$	7,063,347	$	5,667,740	$	7,755,946
Long-term debt (variable-rate)	2	233,500		233,500		224,700		224,700
Total liabilities		$	5,904,334	$	7,296,847	$	5,892,440	$	7,980,646

Puget Sound Energy		March 31, 2021				December 31, 2020
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358
Total liabilities		$	4,338,523	$	5,446,409	$	4,338,044	$	6,086,358

_______________

1 The carrying value includes debt issuances costs of $21.9 million and $22.7 million for March 31, 2021 and December 31, 2020, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.6 million and $22.9 million for March 31, 2021 and December 31, 2020, 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. 2021						Fair Value At December 31, 2020
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	31,980	$	386	$	32,366	$	21,947	$	597	$	22,544
Natural gas derivative instruments	19,677		103		19,780		19,139		137		19,276
Total assets	$	51,657	$	489	$	52,146	$	41,086	$	734	$	41,820
Liabilities:
Electric derivative instruments	$	12,187	$	21,556	$	33,743	$	22,607	$	24,315	$	46,922
Natural gas derivative instruments	8,491		1,937		10,428		13,080		1,272		14,352
Total liabilities	$	20,678	$	23,493	$	44,171	$	35,687	$	25,587	$	61,274

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)	2021						2020
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(23,718)	$	(1,135)	$	(24,853)	$	(3,379)	$	1,282	$	(2,097)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	820		—		820		(24,552)		—		(24,552)
Included in regulatory assets / liabilities	—		(888)		(888)		—		323		323
Settlements	1,728		189		1,917		1,626		(513)		1,113
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		—		—		—
Balance at end of period	$	(21,170)	$	(1,834)	$	(23,004)	$	(26,305)	$	1,092	$	(25,213)

_______________

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 $0.8 million and zero for three months ended March 31, 2021 and 2020, 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, 2021

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	386	$	21,556	Discounted cash flow	Power prices (per MWh)	$	22.87	$	44.21	$	32.56
Natural gas	$	103	$	1,937	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.10	$	3.57	$	2.70

_______________

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, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	597	$	24,315	Discounted cash flow	Power prices (per MWh)	$	22.82	$	41.66	$	31.54
Natural gas	$	137	$	1,272	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.89	$	3.42	$	2.47

___________

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

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets

The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase

contracts' fair value:

Puget Energy
Valuation Date	Unobservable Input	Low	High	Average
March 31, 2020	Power prices (per MWh)	$10.23	$29.05	$20.88
	Power contract costs per quarter (in thousands)	$6,308	$7,085	$6,468

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2021

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, 2021 and 2020:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,502)		—		—		(91)		(97)
Amortization of prior service cost	(476)		(495)		87		87		2		—
Amortization of net loss (gain)	2,830		1,981		587		586		(10)		(22)
Net periodic benefit cost	$	2,562	$	1,279	$	1,082	$	1,279	$	19	$	21

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2021		2020		2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	6,711	$	5,997	$	115	$	228	$	41	$	49
Interest cost	5,578		6,298		293		378		77		91
Expected return on plan assets	(12,081)		(12,504)		—		—		(91)		(97)
Amortization of prior service cost	(378)		(393)		87		87		2		—
Amortization of net loss (gain)	5,311		4,656		635		659		(15)		(36)
Net periodic benefit cost	$	5,141	$	4,054	$	1,130	$	1,352	$	14	$	7

Schedule of Changes in Projected Benefit Obligations

The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2021 and December 31, 2020:

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, 2021		December 31, 2020		March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
Change in benefit obligation:
Benefit obligation at beginning of period	$	849,383	$	774,305	$	46,742	$	63,000	$	12,114	$	11,627
Amendments	—		—		—		—		—		44
Service cost	6,711		24,337		115		756		41		190
Interest cost	5,578		25,180		293		1,464		77		368
Curtailment Loss / (Gain)	—		—		—		—		—		—
Actuarial loss (gain)	—		69,413		—		3,663		—		604
Benefits paid	(11,625)		(42,775)		(496)		(22,141)		(237)		(906)
Medicare part D subsidy received	—		—		—		—		196		187
Administrative Expense	—		(1,077)		—		—		—		—
Benefit obligation at end of period	$	850,047	$	849,383	$	46,654	$	46,742	$	12,191	$	12,114

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

3 Months Ended

Mar. 31, 2021

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, 2021 and December 31, 2020:

Puget Sound Energy
(Dollars in Thousands)	At March 31,		At December 31,
PGA receivable balance and activity	2021		2020
PGA receivable beginning balance	$	87,655	$	132,766
Actual natural gas costs	113,175		314,792
Allowed PGA recovery	(154,592)		(363,886)
Interest	549		3,983
PGA receivable ending balance	$	46,787	$	87,655

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

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Summary of Consolidation and Significant Accounting Policy (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021 USD ($) mi²	Mar. 31, 2020 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Summary of Consolidation Policy
Allowance for Credit Losses, Beginning Balance			$ 20,080	$ 8,294
Provision for Credit Loss	$ 12,452	$ 4,894
Receivables Charged-Off	(2,140)	(3,374)
Allowance for Credit Loss, Ending Balance	$ 30,392	9,814
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000
Variable Interest Entity [Line Items]
Contract Length, PPA	20 years
Variable Interest Entity, Measure of Activity, Expense	$ 5,700
Variable Interest Entity, Payable	$ 3,600
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Construction in Progress, Gross	$ 216,500		207,700
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%
Construction in Progress, Gross	$ 239,400		$ 231,600
Puget LNG [Member]
Summary of Consolidation Policy
Operating Costs and Expenses	$ 200	$ 300

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,108,094	$ 1,017,104
Regulated Operating Revenue, Other	8,588	6,009
Revenues	1,160,086	1,046,130
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	664,102	607,693
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	387,863	365,637
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	56,129	43,774
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	(1,928)	1,150
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	53,920	27,876
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	8,588	6,009
Revenues	$ 1,160,086	$ 1,046,130
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

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Accounting for Derivative Instruments and Hedging Activities Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years
Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 12.0
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	99.20%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	0.80%
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$ 3.2
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 1.0

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Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions		Mar. 31, 2021 USD ($) MMBTU	Dec. 31, 2020 USD ($) MMBTU
Derivative [Line Items]
Current, Assets		$ 47,221	$ 33,015
Long-term, Assets		4,925	8,805
Current, Liabilities		19,839	31,441
Long-term, Liabilities		24,332	29,833
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current, Assets		47,221	33,015
Long-term, Assets		4,925	8,805
Assets	[1]	52,146	41,820
Current, Liabilities		19,839	31,441
Long-term, Liabilities		24,332	29,833
Derivative Liability	[2]	$ 44,171	$ 61,274
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		331.0	320.0
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets		$ 32,366	$ 22,544
Derivative Liability		33,743	46,922
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets		19,780	19,276
Derivative Liability		$ 10,428	$ 14,352
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		221.4	212.2
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		4.4	6.6

[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.

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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, 2021	Dec. 31, 2020
Assets:
Gross Amount Recognized in the Statement of Financial Position	$ 52,146	$ 41,820
Gross Amounts Offset in the Statement of Financial Position	0	0
Assets	52,146	41,820
Commodity Contracts	(21,105)	(21,696)
Cash Collateral Received	0	0
Net Amount	31,041	20,124
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	44,171	61,274
Gross Amounts Offset in the Statement of Financial Position	0	0
Derivative Liability	44,171	61,274
Commodity Contracts	(21,105)	(21,696)
Cash Collateral Posted	(143)	(9,343)
Net Amount	$ 22,923	$ 30,235

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Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 23,002	$ (48,541)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	18,012	(53,180)
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	1,628	(9,755)
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	8,313	1,296
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(13,303)	(5,935)
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	$ 21,374	$ (38,786)

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Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ 29,464	$ 42,885
Posted Collateral	11,990	20,903
Additional Collateral, Aggregate Fair Value	21,991	26,966
Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	12,000
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	3,200
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	21,991	26,966
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	21,991	26,966
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	1,000
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	7,330	6,576
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	143	9,343
Posted Collateral	$ 11,990	$ 20,903

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Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($)	Mar. 31, 2021	Dec. 31, 2020
Liabilities:
Total long-term debt	$ 5,904,334,000	$ 5,892,440,000
Carrying Value [Member] | Level 2 [Member]
Liabilities:
Notes Receivable, Fair Value Disclosure	52,000,000.0	52,700,000
Subsidiaries [Member]
Liabilities:
Total long-term debt	4,338,523,000	4,338,044,000
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	7,296,847,000	7,980,646,000
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	7,063,347,000	7,755,946,000
Long-term debt (variable-rate)	233,500,000	224,700,000
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	5,904,334,000	5,892,440,000
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	5,670,834,000	5,667,740,000
Long-term debt (variable-rate)	233,500,000	224,700,000
Debt issuance costs	21,900,000	22,700,000
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt	5,446,409,000	6,086,358,000
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	5,446,409,000	6,086,358,000
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt	4,338,523,000	4,338,044,000
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	4,338,523,000	4,338,044,000
Debt issuance costs	$ 22,600,000	$ 22,900,000

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Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019
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	$ (23,004)	$ (25,213)	$ (24,853)	$ (2,097)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	820	(24,552)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	(888)	323
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	1,917	1,113
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	0	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	(21,170)	(26,305)	(23,718)	(3,379)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	820	(24,552)
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	1,728	1,626
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	0	0
Gain (loss) on derivatives	800	0
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	(1,834)	1,092	(1,135)	$ 1,282
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)	(888)	323
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	189	(513)
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	0	$ 0
Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	52,146		41,820
Derivative Liability	44,171		61,274
Fair Value, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	32,366		22,544
Derivative Liability	33,743		46,922
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	19,780		19,276
Derivative Liability	10,428		14,352
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	51,657		41,086
Derivative Liability	20,678		35,687
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	31,980		21,947
Derivative Liability	12,187		22,607
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	19,677		19,139
Derivative Liability	8,491		13,080
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	489		734
Derivative Liability	23,493		25,587
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	386		597
Derivative Liability	21,556		24,315
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	103		137
Derivative Liability	$ 1,937		$ 1,272

XML

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2021 USD ($) $ / MWh $ / MMBTU	Mar. 31, 2020 USD ($) $ / MWh	Dec. 31, 2020 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	$ 4,900,000		$ 5,500,000
Wells Project
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		$ 147,168,000
Impairment of Intangible Assets (Excluding Goodwill)		52,565,000
Wells Project | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 94,603,000
Discounted cash flow [Member] | Low [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		10.23
Fair Value Inputs, Power Contract Costs		$ 6,308
Discounted cash flow [Member] | High [Member] | Wells Project
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		29.05
Discounted cash flow [Member] | High [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Power Contract Costs		$ 7,085
Discounted cash flow [Member] | Weighted Average [Member] | Wells Project
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		20.88
Discounted cash flow [Member] | Weighted Average [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Power Contract Costs		$ 6,468
Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	52,146,000		41,820,000
Derivative Liability	44,171,000		61,274,000
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	489,000		734,000
Derivative Liability	$ 23,493,000		$ 25,587,000
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	22.87		22.82
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	44.21		41.66
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	32.56		31.54
Electric Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 32,366,000		$ 22,544,000
Derivative Liability	33,743,000		46,922,000
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	386,000		597,000
Derivative Liability	21,556,000		24,315,000
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	386,000		597,000
Derivative Liability	$ 21,556,000		$ 24,315,000
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	2.10		1.89
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	3.57		3.42
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	2.70		2.47
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 19,780,000		$ 19,276,000
Derivative Liability	10,428,000		14,352,000
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	103,000		137,000
Derivative Liability	1,937,000		1,272,000
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	103,000		137,000
Derivative Liability	$ 1,937,000		$ 1,272,000

XML

Retirement Benefits - Benefit Obligations (Details) - Subsidiaries [Member]	3 Months Ended
	Mar. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Interest Credit	1.00%
employer contribution [Member] | Collective Bargaining Arrangement [Member] | UA represented [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%

XML

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Qualified Pension Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	$ 6,711		$ 24,337
Defined Benefit Plan, Interest Cost	5,578		25,180
Qualified Pension Benefits [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	6,711	$ 5,997
Defined Benefit Plan, Interest Cost	5,578	6,298
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(12,081)	(12,502)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(476)	(495)
Defined Benefit Plan, Amortization of Gain (Loss)	2,830	1,981
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	2,562	1,279
Qualified Pension Benefits [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	6,711	5,997
Defined Benefit Plan, Interest Cost	5,578	6,298
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(12,081)	(12,504)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(378)	(393)
Defined Benefit Plan, Amortization of Gain (Loss)	5,311	4,656
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	5,141	4,054
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	115		756
Defined Benefit Plan, Interest Cost	293		1,464
Supplemental Employee Retirement Plan [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	115	228
Defined Benefit Plan, Interest Cost	293	378
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	87	87
Defined Benefit Plan, Amortization of Gain (Loss)	587	586
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	1,082	1,279
Supplemental Employee Retirement Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	115	228
Defined Benefit Plan, Interest Cost	293	378
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	87	87
Defined Benefit Plan, Amortization of Gain (Loss)	635	659
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	1,130	1,352
Other Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	41		190
Defined Benefit Plan, Interest Cost	77		$ 368
Other Benefit [Member] | Parent Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	41	49
Defined Benefit Plan, Interest Cost	77	91
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(91)	(97)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	2	0
Defined Benefit Plan, Amortization of Gain (Loss)	(10)	(22)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	19	21
Other Benefit [Member] | Subsidiaries [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Service Cost	41	49
Defined Benefit Plan, Interest Cost	77	91
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(91)	(97)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	2	0
Defined Benefit Plan, Amortization of Gain (Loss)	(15)	(36)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	$ 14	$ 7

XML

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	$ 849,383	$ 774,305
Defined Benefit Plan, Service Cost	6,711	24,337
Defined Benefit Plan, Interest Cost	5,578	25,180
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	69,413
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(11,625)	(42,775)
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt	0	0
defined benefit plan expected administration expense	0	1,077
Defined Benefit Plan, Benefit Obligation, Ending Balance	850,047	849,383
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	46,742	63,000
Defined Benefit Plan, Service Cost	115	756
Defined Benefit Plan, Interest Cost	293	1,464
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	3,663
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(496)	(22,141)
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	46,654	46,742
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Beginning Balance	12,114	11,627
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	(44)
Defined Benefit Plan, Service Cost	41	190
Defined Benefit Plan, Interest Cost	77	368
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	0	604
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(237)	(906)
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt	196	187
defined benefit plan expected administration expense	0	0
Defined Benefit Plan, Benefit Obligation, Ending Balance	12,191	12,114
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	0
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
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	0	0
Nonqualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	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, 2021	Mar. 31, 2020	Dec. 31, 2021
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 0.5	$ 13.6
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			6.8
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		4 Months Ended	12 Months Ended				36 Months Ended
	Apr. 12, 2021	Apr. 02, 2021	Feb. 02, 2021	Dec. 09, 2020	Nov. 01, 2020	Sep. 30, 2020	Aug. 31, 2020	Aug. 30, 2020	Jul. 31, 2020	Jul. 08, 2020	Apr. 06, 2020	Jan. 15, 2020	Nov. 01, 2019	Oct. 31, 2019	Jun. 20, 2019	Apr. 10, 2019	Mar. 01, 2019	Jan. 30, 2019	Nov. 07, 2018	Dec. 19, 2017	Dec. 18, 2017	Mar. 31, 2021	Mar. 31, 2020	Apr. 30, 2018	Jul. 19, 2021	Dec. 31, 2020	May 01, 2020	Apr. 30, 2019	Jul. 19, 2023	Aug. 27, 2020	Jul. 21, 2020	Apr. 30, 2020	Dec. 31, 2019	Jan. 01, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Income tax (benefit) expense																						$ 2,153,000	$ 3,984,000
Depreciation & Amortization																						208,431,000	164,816,000
Other Regulatory Assets																						737,377,000				$ 747,651,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities																			7.49%
Income tax (benefit) expense																						16,626,000	13,265,000	$ 34,600,000
Annual Power Cost Variability, Interest																						300,000	500,000
PGA payable																						46,787,000				87,655,000							$ 132,766,000
Depreciation & Amortization																						208,362,000	164,771,000
Liabilities, Other than Long-term Debt, Noncurrent											$ 11,000,000.0																				$ 4,500,000
Customer Bill Assistance											$ 1,000
Other Regulatory Assets																						737,377,000				747,651,000
Subsidiaries [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Customer Bill Assistance	$ 2,500
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period																						23,300,000	9,900,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold																																		$ 10,000,000.0	$ 8,000,000.0
Public Utilities, Rate Case, Deferred Storm Qualifying Costs																																		$ 500,000
Subsidiaries [Member] | Electricity | Subsequent Event [Member]
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	20,000,000.0
Subsidiaries [Member] | Natural Gas | Subsequent Event [Member]
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	$ 7,700,000
General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Return on Equity, Percentage												9.50%			7.62%
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities												7.48%							7.49%	7.60%
Annual Revenue Requirement						$ 25,600,000
Protected Excess Deferred Income Tax																														$ 70,800,000
Fiscal Period Duration															4 years
Unprotected Excess Deferred Income Tax																														$ 38,900,000
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, Requested Rate Increase (Decrease), Amount												$ 1,500,000
Public Utilities, Approved Rate Increase (Decrease), Amount									$ 27,700,000	$ 900,000
Public Utilities, Approved Rate Increase (Decrease), Percentage									1.30%	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									2.90%	1.60%
Public Utilities Attrition Adjustment Increase Decrease Amount										$ 23,900,000
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount									$ 30,100,000
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									$ 200,000	$ 1,300,000
Public Utilities, Approved Rate Increase (Decrease), Percentage									0.02%	0.15%
Public Utilities, Interim Rate Increase (Decrease), Amount									$ 42,900,000	$ 36,500,000
Public Utilities, Interim Rate Increase (Decrease), Percentage									5.60%	4.00%
Public Utilities Attrition Adjustment Increase Decrease Amount										$ 16,200,000
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount									$ 6,400,000
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Return on Equity, Percentage															9.80%
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%
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration																											1 year
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage																			0.90%
Public Utilities, Requested Rate Increase (Decrease), Amount																			$ 18,900,000
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage																			2.70%
Public Utilities, Requested Rate Increase (Decrease), Amount																	$ 6,100,000		$ 21,700,000
Public Utilities, Approved Rate Increase (Decrease), Amount																	$ 25,900,000	$ 21,500,000
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																												$ (72,900,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																												(3.40%)
Contract with Customer, Refund Liability																																$ 100,000
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																												$ (23,600,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																												(2.70%)
Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Deferred Revenue, Revenue Recognized																						0
Decoupling Mechanism [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration							2 years	1 year
Amortization							$ 16,000,000.0
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized																						900,000
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage																				3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage																				5.00%	3.00%
Purchased Gas Adjustment [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 32,600,000								$ 17,800,000
Purchased natural gas costs																						113,175,000				314,792,000
Purchased natural gas costs, recoverable																						(154,592,000)				(363,886,000)
Purchased natural gas adjustment, interest																						549,000				3,983,000
Annual revenue					37,400,000								100,600,000
Out of Cycle PGA					$ 69,400,000								54,000,000.0
Under collected commodity balances													114,400,000
Commodity Costs													10,800,000
Refund to Customers, remaining balance													4,100,000
Refund to Customers													$ 54,700,000
Fiscal Period Duration							3 years						2 years	1 year
Other Regulatory Assets																											$ 4,900,000
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																						4,600,000				$ 2,800,000
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			4.10%	3.70%
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 88,000,000.0	$ 78,500,000
Power Cost Only Rate Case | Subsidiaries [Member] | Electricity, US Regulated [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage		3.10%
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 65,300,000
Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period																							$ 0
Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period																						200,000
storm that occurred in 2020 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period																						$ 12,900,000
Forecast [Member] | General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration																									12 months				36 months

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Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions		3 Months Ended		12 Months Ended
	Dec. 31, 2019 USD ($)	Mar. 31, 2021 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Interest		$ 0.3	$ 0.5
Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount		11.4	25.1	$ 67.2
Customer's share [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount		$ 0.0	$ 4.0	36.0
Customer's share [Member] | Range 1 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0
Customer's share [Member] | Range 1 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0
Customer's share [Member] | Range 2 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.50
Customer's share [Member] | Range 2 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.65
Customer's share [Member] | Range 3 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.90
Customer's share [Member] | Range 3 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.90
Companys share [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount				31.2
Companys share [Member] | Range 1 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		1
Companys share [Member] | Range 1 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		1
Companys share [Member] | Range 2 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.50
Companys share [Member] | Range 2 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.35
Companys share [Member] | Range 3 [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.10
Companys share [Member] | Range 3 [Member] | Over-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability		0.10
Customer's share plus interest | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount	$ 41.7			37.0	$ 4.7
Customer's share plus interest | Maximum Power
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount				$ 20.0

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Commitments and Contingencies (Details)	3 Months Ended
	Mar. 31, 2021 USD ($)	Dec. 10, 2019 USD ($) MW
Loss Contingencies [Line Items]
Purchase Obligation	$ 777,400,000
Subsidiaries [Member] | Electricity
Loss Contingencies [Line Items]
Change in Load, Percentage	0.10%
Subsidiaries [Member] | Natural Gas
Loss Contingencies [Line Items]
Change in Load, Percentage	(3.70%)
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Jointly owned utility plant	2
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%
Colstrip Unit 4 | Subsidiaries [Member]
Loss Contingencies [Line Items]
Colstrip 4 Sale Amount		$ 1
Colstrip PPA | MW		90

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Leases (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($)
Leases [Abstract]
ROU Asset, Modification, Operating	$ 26.3

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Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Lessee, Operating Lease, Description [Abstract]
Operating Lease, Right-of-Use Asset	$ 194,245	$ 172,167
Operating Lease, Liability, Current	19,238	19,204
Operating Lease, Liability, Noncurrent	$ 182,288	$ 160,980

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Other (Details) - USD ($)		3 Months Ended
	Mar. 31, 2020	Mar. 31, 2021
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Amount Outstanding During Period		$ 23,500,000
Line of Credit Facility, Maximum Borrowing Capacity		800,000,000.0
Subsidiaries [Member]
Short-term Debt [Line Items]
Commercial Paper		$ 191,000,000.0
Subsidiaries [Member] | Working Capital Needs [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 0