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 June 30, 2020

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	6
Item 1.	Financial Statements	6
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2020 and 2019	6
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2020 and 2019	7
	Consolidated Balance Sheets – June 30, 2020 and December 31, 2019	8
	Consolidated Statements of Common Shareholder's Equity - June 30, 2020, and December 31, 2019	10
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2020 and 2019	11
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2020 and 2019	12
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2020 and 2019	13
	Consolidated Balance Sheets – June 30, 2020 and December 31, 2019	14
	Consolidated Statements of Common Shareholder's Equity - June 30, 2020, and December 31, 2019	16
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2020 and 2019	17
	Notes
	Combined Notes to Consolidated Financial Statements	18
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	73
Item 4.	Controls and Procedures	74
Part II.	Other Information	75
Item 1.	Legal Proceedings	75
Item 1A.	Risk Factors	75
Item 6.	Exhibits	75
Exhibit Index		75
Signatures		77

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 and 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 or weather conditions 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; and

● 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.

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, 2019.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Operating revenue:
Electric	$	468,366	$	510,742	$	1,137,456	$	1,309,670
Natural gas	177,609		153,457		548,640		458,125
Other	5,704		6,731		11,713		17,974
Total operating revenue	651,679		670,930		1,697,809		1,785,769
Operating expenses:
Energy costs:
Purchased electricity	125,487		124,001		291,229		394,703
Electric generation fuel	32,974		37,601		96,598		114,800
Residential exchange	(16,167)		(15,972)		(40,801)		(41,135)
Purchased natural gas	61,257		41,116		216,133		140,503
Unrealized (gain) loss on derivative instruments, net	(12,162)		30,332		36,379		15,145
Utility operations and maintenance	148,120		149,424		303,042		307,379
Non-utility expense and other	15,841		10,620		28,803		24,377
Depreciation & amortization	136,865		164,715		301,681		345,412
Conservation amortization	20,321		20,029		47,714		53,315
Taxes other than income taxes	68,793		69,949		174,297		178,695
Total operating expenses	581,329		631,815		1,455,075		1,533,194
Operating income(loss)	70,350		39,115		242,734		252,575
Other income (expense):
Other income	16,576		15,439		30,635		29,003
Other expense	(8,468)		(1,825)		(10,750)		(3,601)
Interest charges:
AFUDC	3,914		3,570		7,557		6,920
Interest expense	(106,793)		(87,770)		(195,677)		(175,786)
Income (loss) before income taxes	(24,421)		(31,471)		74,499		109,111
Income tax (benefit) expense	(1,188)		1,481		2,796		9,909
Net income (loss)	$	(23,233)	$	(32,952)	$	71,703	$	99,202

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Net income (loss)	$	(23,233)	$	(32,952)	$	71,703	$	99,202
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $433, $25, $1,806 and $50, respectively	1,630		91		6,800		183
Other comprehensive income (loss)	1,630		91		6,800		183
Comprehensive income (loss)	$	(21,603)	$	(32,861)	$	78,503	$	99,385

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

6

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	June 30, 2020		December 31, 2019
Utility plant (at original cost, including construction work in progress of $720,680 and $591,199 respectively):
Electric plant	$	8,999,303	$	8,811,889
Natural gas plant	4,078,221		3,916,040
Common plant	1,093,033		1,096,649
Less: Accumulated depreciation and amortization	(3,460,359)		(3,236,240)
Net utility plant	10,710,198		10,588,338
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	313,557		286,975
Total other property and investments	1,970,070		1,943,488
Current assets:
Cash and cash equivalents	27,434		45,259
Restricted cash	28,777		20,887
Accounts receivable, net of allowance for doubtful accounts of $10,899 and $8,294, respectively	235,712		316,352
Unbilled revenue	116,225		224,657
Materials and supplies, at average cost	131,521		115,684
Fuel and natural gas inventory, at average cost	51,290		52,083
Unrealized gain on derivative instruments	27,419		23,626
Prepaid expense and other	27,675		27,504
Power contract acquisition adjustment gain	10,865		9,067
Total current assets	656,918		835,119
Other long-term and regulatory assets:
Power cost adjustment mechanism	62,269		41,745
Purchased gas adjustment receivable	86,933		132,766
Regulatory assets related to power contracts	12,678		14,146
Other regulatory assets	683,345		673,021
Unrealized gain on derivative instruments	7,124		7,682
Power contract acquisition adjustment gain	90,978		147,530
Operating lease right-of-use asset	179,658		183,048
Other	87,840		92,980
Total other long-term and regulatory assets	1,210,825		1,292,918
Total assets	$	14,548,011	$	14,659,863

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	June 30, 2020		December 31, 2019
Capitalization
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—	$	—
Additional paid-in capital	3,308,957		3,308,957
Retained earnings	802,130		775,491
Accumulated other comprehensive income (loss), net of tax	(77,349)		(84,149)
Total common shareholder’s equity	4,033,738		4,000,299
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	2,234,000		1,758,100
Debt discount issuance costs and other	(211,330)		(211,635)
Total long-term debt	6,396,530		5,920,325
Total capitalization	10,430,268		9,920,624
Current liabilities:
Accounts payable	270,947		325,913
Short-term debt	140,000		176,000
Current maturities of long-term debt	2,412		452,412
Accrued expenses:
Taxes	93,973		99,979
Salaries and wages	41,395		50,091
Interest	74,927		74,855
Unrealized loss on derivative instruments	29,769		13,428
Power contract acquisition adjustment loss	2,197		2,418
Operating lease liabilities	16,609		15,862
Other	83,714		107,809
Total current liabilities	755,943		1,318,767
Other long-term and regulatory liabilities:
Deferred income taxes	843,384		824,720
Unrealized loss on derivative instruments	34,172		12,693
Regulatory liabilities	719,587		730,879
Regulatory liability for deferred income taxes	931,063		946,179
Regulatory liabilities related to power contracts	101,843		156,597
Power contract acquisition adjustment loss	10,481		11,728
Operating lease liabilities	170,250		174,327
Other deferred credits	551,020		563,349
Total long-term and regulatory liabilities	3,361,800		3,420,472
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	14,548,011	$	14,659,863

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, 2018	200	$	—	$	3,308,957	$	629,003	$	(77,202)	$	3,860,758
Net income (loss)	—	—		—		132,154		—		132,154
Common stock dividend paid	—	—		—		(35,994)		—		(35,994)
Other comprehensive income (loss)	—	—		—		—		92		92
Balance at March 31, 2019	200	$	—	$	3,308,957	$	725,163	$	(77,110)	$	3,957,010
Net income (loss)	—	—		—		(32,952)		—		(32,952)
Common stock dividend paid	—	—		—		(83)		—		(83)
Other comprehensive income (loss)	—	—		—		—		91		91
Balance at June 30, 2019	200	$	—	$	3,308,957	$	692,128	$	(77,019)	$	3,924,066
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
Net income (loss)	—	—		—		(23,233)		—		(23,233)
Common stock dividend paid	—	—		—		(22,419)		—		(22,419)
Other comprehensive income (loss)	—	—		—		—		1,630		1,630
Balance at June 30, 2020	200	$	—	$	3,308,957	$	802,130	$	(77,349)	$	4,033,738

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)

	Six Months Ended June 30,
	2020		2019
Operating activities:
Net Income (loss)	$	71,703	$	99,202
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	301,681		345,412
Conservation amortization	47,714		53,315
Deferred income taxes and tax credits, net	1,741		2,248
Net unrealized (gain) loss on derivative instruments	36,379		15,145
(Gain) or loss on extinguishment of debt	13,546		—
AFUDC - equity	(11,668)		(6,591)
Production tax credit utilization	(14,470)		(41,111)
Other non-cash	696		7,427
Regulatory assets and liabilities	(71,268)		(19,061)
Purchased gas adjustment	45,833		(144,917)
Other long term assets and liabilities	(11,114)		(13,238)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	189,072		203,174
Materials and supplies	(15,837)		(3,769)
Fuel and natural gas inventory	793		(5,338)
Prepayments and other	(171)		(85)
Purchased gas adjustment	—		9,921
Accounts payable	(54,136)		(179,533)
Taxes payable	(6,006)		(20,798)
Other	(28,226)		(10,692)
Net cash provided by (used in) operating activities	496,262		290,711
Investing activities:
Construction expenditures - excluding equity AFUDC	(438,477)		(470,335)
Other	104		(3,977)
Net cash provided by (used in) investing activities	(438,373)		(474,312)
Financing activities:
Change in short-term debt, net	(36,000)		160,703
Dividends paid	(45,064)		(36,077)
Proceeds from long-term debt and bonds issued	644,690		20,000
Redemption of bonds and notes	(450,000)		—
Repayment of term loan and revolving credit	(174,100)		—
Other	(7,350)		7,411
Net cash provided by (used in) financing activities	(67,824)		152,037
Net increase (decrease) in cash, cash equivalents, and restricted cash	(9,935)		(31,564)
Cash, cash equivalents, and restricted cash at beginning of period	66,146		55,562
Cash, cash equivalents, and restricted cash at end of period	$	56,211	$	23,998
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	169,832	$	165,863
Cash payments (refunds) for income taxes	—		5,376
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	57,498	$	73,757
Reclassification of Colstrip from utility plant to a regulatory asset(Note 8)	—		(47,516)

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Operating revenue:
Electric	$	468,366	$	510,742	$	1,137,456	$	1,309,670
Natural gas	177,609		153,457		548,640		458,125
Other	5,704		6,731		11,713		17,974
Total operating revenue	651,679		670,930		1,697,809		1,785,769
Operating expenses:
Energy costs:
Purchased electricity	125,487		124,001		291,229		394,703
Electric generation fuel	32,974		37,601		96,598		114,800
Residential exchange	(16,167)		(15,972)		(40,801)		(41,135)
Purchased natural gas	61,257		41,116		216,133		140,503
Unrealized (gain) loss on derivative instruments, net	(12,162)		30,332		36,379		15,145
Utility operations and maintenance	148,120		149,424		303,042		307,379
Non-utility expense and other	15,048		9,978		27,783		23,055
Depreciation & amortization	136,816		164,692		301,587		345,370
Conservation amortization	20,321		20,029		47,714		53,315
Taxes other than income taxes	68,793		69,949		174,297		178,695
Total operating expenses	580,487		631,150		1,453,961		1,531,830
Operating income(loss)	71,192		39,780		243,848		253,939
Other income (expense):
Other income	12,862		12,412		24,145		22,961
Other expense	(8,468)		(1,825)		(10,750)		(3,601)
Interest charges:
AFUDC	3,914		3,570		7,557		6,920
Interest expense	(62,464)		(59,935)		(123,178)		(120,085)
Income (loss) before income taxes	17,036		(5,998)		141,622		160,134
Income tax (benefit) expense	1,999		2,327		15,264		21,157
Net income (loss)	$	15,037	$	(8,325)	$	126,358	$	138,977

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 June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Net income (loss)	$	15,037	$	(8,325)	$	126,358	$	138,977
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,025, $667, $3,072 and $1,335, respectively	3,860		2,512		11,570		5,022
Amortization of treasury interest rate swaps to earnings, net of tax of $25, $26, $51 and $51 respectively	96		96		192		192
Other comprehensive income (loss)	3,956		2,608		11,762		5,214
Comprehensive income (loss)	$	18,993	$	(5,717)	$	138,120	$	144,191

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

11

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	June 30, 2020		December 31, 2019
Utility plant (at original cost, including construction work in progress of $720,680 and $591,199 respectively):
Electric plant	$	10,846,456	$	10,671,328
Natural Gas plant	4,638,729		4,478,048
Common plant	1,117,680		1,121,568
Less:  Accumulated depreciation and amortization	(5,892,667)		(5,682,606)
Net utility plant	10,710,198		10,588,338
Other property and investments:
Other property and investments	82,129		81,112
Total other property and investments	82,129		81,112
Current assets:
Cash and cash equivalents	26,930		44,004
Restricted cash	28,777		20,887
Accounts receivable, net of allowance for doubtful accounts of $10,899 and $8,294, respectively	256,168		319,229
Unbilled revenue	116,225		224,657
Materials and supplies, at average cost	131,521		115,684
Fuel and natural gas inventory, at average cost	50,089		50,818
Unrealized gain on derivative instruments	27,419		23,626
Prepaid expense and other	27,675		27,504
Total current assets	664,804		826,409
Other long-term and regulatory assets:
Power cost adjustment mechanism	62,269		41,745
Purchased gas adjustment receivable	86,933		132,766
Other regulatory assets	683,345		673,021
Unrealized gain on derivative instruments	7,124		7,682
Operating lease right-of-use asset	179,658		183,048
Other	86,052		90,924
Total other long-term and regulatory assets	1,105,381		1,129,186
Total assets	$	12,562,512	$	12,625,045

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

	June 30, 2020		December 31, 2019
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	777,742		751,193
Accumulated other comprehensive income (loss), net of tax	(176,715)		(188,477)
Total common shareholder’s equity	4,086,991		4,048,680
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	(36,770)		(37,718)
Total long-term debt	4,337,090		4,336,142
Total capitalization	8,424,081		8,384,822
Current liabilities:
Accounts payable	272,570		325,980
Short-term debt	140,000		176,000
Current maturities of long-term debt	2,412		2,412
Accrued expenses:
Taxes	97,917		99,977
Salaries and wages	41,395		50,091
Interest	48,087		48,917
Unrealized loss on derivative instruments	29,769		13,428
Operating lease liabilities	16,609		15,862
Other	83,714		107,809
Total current liabilities	732,473		840,476
Other long-term and regulatory liabilities:
Deferred income taxes	1,005,679		977,163
Unrealized loss on derivative instruments	34,172		12,693
Regulatory liabilities	718,386		729,614
Regulatory liabilities for deferred income tax	931,814		946,936
Operating lease liabilities	170,250		174,327
Other deferred credits	545,657		559,014
Total long-term and regulatory liabilities	3,405,958		3,399,747
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	12,562,512	$	12,625,045

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, 2018	85,903,791		$	859	$	3,275,105	$	622,844	$	(190,884)	$	3,707,924
Net income (loss)	—		—		—		147,302		—		147,302
Common stock dividend paid	—		—		—		(64,604)		—		(64,604)
Other comprehensive income (loss)	—		—		—		—		2,606		2,606
Balance at March 31, 2019	85,903,791		$	859	$	3,275,105	$	705,542	$	(188,278)	$	3,793,228
Net income (loss)	—		—		—		(8,325)		—		(8,325)
Common stock dividend paid	—		—		—		(19,384)		—		(19,384)
Other comprehensive income (loss)	—		—		—		—		2,608		2,608
Balance at June 30, 2019	85,903,791		$	859	$	3,275,105	$	677,833	$	(185,670)	$	3,768,127
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
Net income (loss)	—		—		—		15,037		—		15,037
Common stock dividend paid	—		—		—		(46,015)		—		(46,015)
Other comprehensive income (loss)	—		—		—		—		3,956		3,956
Balance at June 30, 2020	$	85,903,791	$	859	$	3,485,105	$	777,742	$	(176,715)	$	4,086,991

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)

	Six Months Ended June 30,
	2020		2019
Operating activities:
Net Income (loss)	$	126,358	$	138,977
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	301,587		345,370
Conservation amortization	47,714		53,315
Deferred income taxes and tax credits, net	10,267		8,967
Net unrealized (gain) loss on derivative instruments	36,379		15,145
AFUDC - equity	(11,668)		(6,591)
Production tax credit utilization	(14,470)		(41,111)
Other non-cash	(4,582)		2,210
Regulatory assets and liabilities	(71,204)		(19,061)
Purchased gas adjustment	45,833		(144,917)
Other long term assets and liabilities	(5,073)		(9,822)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	186,425		206,228
Materials and supplies	(15,837)		(3,769)
Fuel and natural gas inventory	729		(5,338)
Prepayments and other	(171)		(85)
Purchased gas adjustment	—		9,921
Accounts payable	(52,580)		(179,591)
Taxes payable	(2,060)		(20,679)
Other	(28,724)		(7,893)
Net cash provided by (used in) operating activities	548,923		341,276
Investing activities:
Construction expenditures - excluding equity AFUDC	(428,775)		(451,215)
Other	104		(3,977)
Net cash provided by (used in) investing activities	(428,671)		(455,192)
Financing activities:
Change in short-term debt, net	(36,000)		160,703
Dividends paid	(99,809)		(83,988)
Other	6,373		7,410
Net cash provided by (used in) financing activities	(129,436)		84,125
Net increase (decrease) in cash, cash equivalents, and restricted cash	(9,184)		(29,791)
Cash, cash equivalents, and restricted cash at beginning of period	64,891		53,493
Cash, cash equivalents, and restricted cash at end of period	$	55,707	$	23,702
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	114,027	$	112,058
Cash payments (refunds) for income taxes	—		9,784
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	57,498	$	73,757
Reclassification of Colstrip from utility plant to a regulatory asset(Note 8)	—		(47,516)

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, (Puget LNG) 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

On January 1, 2020, the Company adopted ASU 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables.

The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial.

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 following table presents the activity in the allowance for credit losses for accounts receivable for the six months ending June 30, 2020:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	June 30, 2020
Allowance for credit losses:
Beginning balance	$	8,294
Provision for credit loss expense	9,762
Receivables charged-off	(7,157)
Total ending allowance balance	$	10,899

16

Tacoma LNG Facility

In August 2015, PSE filed a proposal with the Washington Utilities and Transportation Commission (Washington Commission) to develop an 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 greenhouse gas (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.

If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the 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, $224.5 million and $199.9 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 June 30, 2020, and December 31, 2019, respectively. Additionally, $0.7 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for each of the six months ended June 30, 2020, and June 30, 2019, respectively. Additionally, $185.1 million and $162.8 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 June 30, 2020, and December 31, 2019, respectively, as PSE is a regulated entity.

(2)  New Accounting Pronouncements

Credit Losses

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables. It also applies to off-balance sheet credit exposures not accounted for as insurance and net investments in leases recognized by a lessor in accordance with Topic 842.

The Company adopted ASC 326 using the modified retrospective method for all financial assets measured at amortized cost. Results for reporting periods beginning after January 1, 2020, are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact was immaterial and the Company did not record a transition adjustment to retained earnings.

Fair Value Measurement

In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement". The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 5, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it has no material impact on the Company's results of operations, cash flows, or consolidated balance sheets.

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 June 30, 2020, the Company has not utilized any of the

17

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.

Accounting Standards Issued but Not Yet Adopted

Retirement Benefits

In August 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures.

The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Accordingly, the Company will implement this update as of December 31, 2020 on a retrospective basis to all periods presented. The Company is in the process of evaluating potential impacts of these amendments to the required annual retirement benefits disclosures.

(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 June 30,				Six Months Ended June 30,
Revenue from contracts with customers:	2020		2019		2020		2019
Electric retail	$	433,112	$	463,219	$	1,040,805	$	1,100,408
Natural gas retail	168,117		145,222		533,753		467,782
Other	34,495		36,546		77,378		172,595
Total revenue from contracts with customers	635,724		644,987		1,651,936		1,740,785
Alternative revenue programs	19,750		4,351		20,900		(20,880)
Other non-customer revenue	(3,795)		21,592		24,973		65,864
Total operating revenue	$	651,679	$	670,930	$	1,697,809	$	1,785,769

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.

18

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.

(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.

19

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
	June 30, 2020					December 31, 2019
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	20,289	$	54,238	*	$	19,933	$	17,504
Natural gas derivatives (MMBtus)3	280.7 million	14,254		9,703		315.5 million	11,375		8,617
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121
Current		$	27,419	$	29,769		$	23,626	$	13,428
Long-term		7,124		34,172			7,682		12,693
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121

_______________

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 234.0 million One Million British Thermal Units (MMBtu) and purchased electricity of

7.1 million Megawatt Hours (MWhs) at June 30, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.

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 June 30, 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	$	34,543	$	—	$	34,543	$	(24,528)	$	—	$	10,015
Liabilities:
Energy derivative contracts	$	63,941	$	—	$	63,941	$	(24,528)	$	—	$	39,413

20

Puget Energy and Puget Sound Energy	At December 31, 2019
	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	$	31,308	$	—	$	31,308	$	(14,922)	$	—	$	16,386
Liabilities:
Energy derivative contracts	$	26,121	$	—	$	26,121	$	(14,922)	$	2,000	$	13,199

_______________

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 June 30,				Six Months Ended June 30,
(Dollars in Thousands)	Classification	2020		2019		2020		2019
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	4,764	$	(17,189)	$	(4,990)	$	(2,228)
Realized	Electric generation fuel	(743)		(1,333)		553		11,995
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	7,398		(13,143)		(31,388)		(12,917)
Realized	Purchased electricity	(6,228)		4,961		(12,163)		41,253
Total gain (loss) recognized in income on derivatives		$	5,191	$	(26,704)	$	(47,988)	$	38,103

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 June 30, 2020, approximately 98.0% 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 2.1% 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.

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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 June 30, 2020, PSE had cash posted as collateral of $9.0 million related to contracts executed on the ICE platform. Also, as of June 30, 2020, PSE had $6.3 million in a 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 six months ended June 30, 2020.

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 June 30, 2020						At December 31, 2019
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	28,552	$	—	$	28,552	$	6,110	$	—	$	6,110
Requested credit for adequate assurance	6,331		—		—		5,253		—		—
Forward value of contract3	5,327		—		N/A		—		14,827		N/A
Total	$	40,210	$	—	$	28,552	$	11,363	$	14,827	$	6,110

_______________

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.

22

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 totaling $52.5 million at June 30, 2020, and $51.5 million at December 31, 2019, 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		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,162,530	$	7,608,405	$	5,512,225	$	7,004,316
Long-term debt (variable-rate)	2	234,000		234,000		408,100		408,100
Total liabilities		$	6,396,530	$	7,842,405	$	5,920,325	$	7,412,416

Puget Sound Energy		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818
Total liabilities		$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818

_______________

¹ The carrying value includes debt issuances costs of $23.1 million and $24.1 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

² The carrying value includes debt issuances costs of $23.6 million and $24.4 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

23

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 June 30, 2020						Fair Value At December 31, 2019
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	19,763	$	526	$	20,289	$	19,282	$	651	$	19,933
Natural gas derivative instruments	13,634		620		14,254		9,852		1,523		11,375
Total assets	$	33,397	$	1,146	$	34,543	$	29,134	$	2,174	$	31,308
Liabilities:
Electric derivative instruments	$	25,103	$	29,135	$	54,238	$	13,474	$	4,030	$	17,504
Natural gas derivative instruments	9,425		278		9,703		8,376		241		8,617
Total liabilities	$	34,528	$	29,413	$	63,941	$	21,850	$	4,271	$	26,121

The following tables present 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 June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(26,305)	$	1,092	$	(25,213)	$	5,012	$	2,758	$	7,770
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	(2,284)		—		(2,284)		(6,190)		—		(6,190)
Included in regulatory assets / liabilities	—		(39)		(39)		—		382		382
Settlements	(20)		(711)		(731)		574		(1,619)		(1,045)
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		(1,842)		877		(965)
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

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Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(3,378)	$	1,282	$	(2,096)	$	1,362	$	1,673	$	3,035
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2	(26,837)		—		(26,837)		6,135		—		6,135
Included in regulatory assets / liabilities	—		284		284		—		2,279		2,279
Settlements	1,606		(1,224)		382		(12,909)		(2,718)		(15,627)
Transferred into Level 3	—		—		—		4,391		(398)		3,993
Transferred out of Level 3	—		—		—		(1,425)		1,562		137
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

_______________

^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 $(23.1) million and $(4.7) million for three months ended June 30, 2020 and 2019, respectively.

^2. 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 $(25.4) million and $(2.4) million for six months ended June 30, 2020 and 2019, 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 June 30, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	526	$	29,135	Discounted cash flow	Power prices (per MWh)	$	22.97	$	40.05	$	30.14
Natural gas	$	620	$	278	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.10	$	3.08	$	1.78

_______________

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, 2019:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	651	$	4,030	Discounted cash flow	Power prices (per MWh)	$	9.00	$	43.85	$	33.99
Natural gas	$	1,523	$	241	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.25	$	3.18	$	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 June 30, 2020, and December 31, 2019, a hypothetical 10.0% 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 $5.6 million and $2.5 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.

At March 31, 2020, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. 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". Differences between the fair market value and the carrying value of assets held at PSE were recorded at PE. The Rocky Reach contract was determined to be impaired due to a decrease in forward prices for this contract of 7.6% from December 31, 2019, causing an impairment of $52.6 million. While this impairment of the intangible asset held at Puget Energy is the result of a decline in forward prices and the corresponding valuation impact, the underlying power purchase contract is included within rates at PSE.

26

The following table presents the impairment recorded to the Company's intangible asset contracts, 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	$	21.27
	Power contract costs per quarter (in thousands)	$	6,308	$	7,085	$	6,468
December 31, 2019	Power prices (per MWh)	$	11.75	$	31.44	$	22.53
	Power contract costs per quarter (in thousands)	$	6,237	$	7,087	$	6,421

(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. 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. Non-represented employees and 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 (Other Benefits) 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.

27

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 and six months ended June 30, 2020 and 2019:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,449)		(12,624)		—		—		(98)		(98)
Amortization of prior service cost	(292)		(495)		87		83		—		—
Amortization of net loss (gain)	2,099		251		512		341		(19)		(63)
Net periodic benefit cost	$	1,822	$	(365)	$	1,137	$	1,258	$	22	$	(33)

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,951)		(25,248)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(990)		174		166		—		—
Amortization of net loss (gain)	4,080		501		1,098		683		(41)		(125)
Net periodic benefit cost	$	3,101	$	(730)	$	2,416	$	2,518	$	43	$	(63)

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,451)		(12,628)		—		—		(98)		(98)
Amortization of prior service cost	(393)		(393)		87		83		—		—
Amortization of net loss (gain)	4,866		3,165		575		433		(33)		(109)
Net periodic benefit cost	$	4,486	$	2,647	$	1,200	$	1,350	$	8	$	(79)

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Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,955)		(25,257)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(787)		174		167		—		—
Amortization of net loss (gain)	9,522		6,330		1,234		866		(69)		(219)
Net periodic benefit cost	$	8,539	$	5,293	$	2,552	$	2,702	$	15	$	(157)

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2020 and December 31, 2019:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended		Year Ended		Six Months Ended		Year Ended		Six Months Ended		Year Ended
(Dollars in Thousands)	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Change in benefit obligation:
Benefit obligation at beginning of period	$	774,305	$	677,643	$	63,000	$	55,708	$	11,627	$	10,636
Amendments	—		—		—		—		—		9,049
Service cost	12,169		22,656		404		1,023		95		61
Interest cost	12,590		28,913		740		2,314		184		410
Curtailment Loss / (Gain)	—		—		—		—		—		(7,486)
Actuarial loss (gain)	1,134		84,272		(478)		6,756		34		(287)
Benefits paid	(23,990)		(36,740)		(17,643)		(2,801)		(494)		(982)
Medicare part D subsidy received	—		—		—		—		187		226
Administrative Expense	—		(2,439)		—		—		—		—
Benefit obligation at end of period	$	776,208	$	774,305	$	46,023	$	63,000	$	11,633	$	11,627

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, 2020, are expected to be at least $18.0 million, $26.1 million and $0.3 million, respectively. During the six months ended June 30, 2020, the Company contributed $17.6 million to fund the SERP. During the six months ended June 30, 2019, the Company contributed $1.0 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans.

29

(7) Regulation and Rates

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 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 which 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 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 $31.0 million, or 1.5% and the natural gas increase to $7.7 million, or 1.0%. PSE continues to review the original Commission order including the ramifications of certain tax issues and the order for clarification and expects to file a Compliance Filing to amend electric and natural gas tariffs and, upon approval of this filing, rates will go into effect.

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

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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 GRC that was filed June 20, 2019:

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.

As a result of the Washington Commission's final order in the ERF, the 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 from January 1, 2018, through February 28, 2019, was 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 will 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. 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 period July 2020 through July 2021. As noted above, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items including administration of the required pass back of excess deferred tax reversals. On July 31, 2020, PSE received an order granting PSE’s motion for clarification which adjusted certain items within the final order, including treatment of protected excess deferred taxes. PSE is currently reviewing the order granting the motion for clarification.

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

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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 also be changed in a power cost only rate case (PCORC). 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 June 30, 2020, 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 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 $2.1 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore an adjustment was booked to 2020 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2020 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 six months ended June 30, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $48.8 million of which $19.5 million was apportioned to customers and $1.1 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $46.4 million for the six months ended June 30, 2019, of which $17.3 million was apportioned to customers and accrued $0.2 million interest on the total deferred customer balance. The under recovery in 2020 led to an increase in the PCA deferral, and was a higher under recovery compared to the same period in 2019. The under recovery was due to power costs that were higher than what was collected in the allowed baseline for the six months ended June 30, 2020. Power costs have increased due to a number of factors such as the addition of new resources, increased rates on purchase power agreements and higher transmission costs. Also contributing to the under recovery in 2020 was a reduced load, used to calculate the baseline amount, which was due to warmer than normal weather in the first half of 2020 and to the effects of COVID-19 on energy usage and the economy. Contributing to the under recovery in 2019 were high power prices in the first quarter of 2019 due to cold weather in February and early March of 2019, which drove regional loads and demand for power up resulting in higher prices, and Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices.

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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 remains which PSE will request to be amortized in its upcoming 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 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 Enbridge pipeline rupture, 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 was approved to collect $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. Finally, as part of the GRC final order, collection of the $114.4 million commodity deferrals and related interest was further lengthened to be collected over three years instead of two.

The following table presents the PGA mechanism balances and activity for six months ended June 30, 2020 and 2019:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30,		At December 31
PGA receivable balance and activity	2020		2019
PGA receivable beginning balance	$	132,766	$	9,922
Actual natural gas costs	169,697		406,162
Allowed PGA recovery	(217,916)		(289,876)
Interest	2,385		6,558
PGA receivable ending balance	$	86,932	$	132,766

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. As of June 30, 2020, and December 31, 2019, PSE had deferred GTZ depreciation expense balances of $41.1 million and $21.7 million, respectively. In addition to the depreciation expense deferral, PSE 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. As of June 30, 2020, and December 31, 2019, PSE has a deferred carrying charge balance of $2.0 million and $0.5 million, respectively. 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 general rate case 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 its next GRC. Finally, the final order changed the rate at which PSE could defer and recovery carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC.

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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. 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 will automatically end when all of the funds are disbursed or September 30, 2020 whichever is soonest. 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.

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that 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 six months ended June 30, 2020, PSE incurred $9.9 million in storm-related electric transmission and distribution system restoration costs, of which no amount was deferred as a regulatory asset. This compares to $39.2 million incurred in storm-related electric transmission and distribution system restoration costs for the six months ended June 30, 2019, of which the Company deferred $0.4 million and $28.3 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. 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. 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 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. The final order in the 2019 GRC further shortened the depreciable life for Colstrip 3 and 4 to December 31, 2025 to align with the requirements of the Clean Energy Transformation Act.

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 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 PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

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On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under the agreement with NorthWestern Energy, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has 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. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. Both the Washington Commission and the Montana Public Service Commission have placed the respective procedural calendars on hold until the terms of the deal can be updated for the additional Colstrip owner’s contractual purchase right and supplemental testimony can be filed. The original purchase agreement is written such that the purchase must close by December 31, 2020. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2019, and June 30, 2020, and determined that these criteria were not met. As such, 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, 2019.

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, 2019, during the six months ended June 30, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $935.3 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, 2019.

COVID-19

The outbreak of the novel coronavirus (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 June 30, 2020, the Company delivered lower electric and natural gas loads, 7.0% and 11.0%, 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 reductions were partially offset by 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 2020, 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.

(9)  Leases

PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the Tacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.

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During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of

$14.7 million.

The components of lease cost were as follows:

Puget Energy and Puget Sound Energy	Three Months Ended June 30,				Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019
Finance lease cost:
Amortization of right-of-use asset	$	152	$	124	$	304	$	282
Interest on lease liabilities	9		10		19		19
Total finance lease cost	$	161	$	134	$	323	$	301
Operating lease cost1	$	5,669	$	5,223	$	11,149	$	10,007

_______________

¹ Includes $0.2 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended June 30, 2020 and 2019, respectively and $0.5 million for each of the six months ended June 30, 2020 and 2019, respectively.

Supplemental cash flow information related to leases was as follows:

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	$	7,726	$	9,131
Investing cash flow for operating leases1	3,423		876
Operating cash flow for finance leases	19		19
Financing cash flow for finance leases	304		282
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	4,996		1,840

_______________

¹ Includes $0.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the six months ended June 30, 2020 and 2019, respectively.

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Supplemental balance sheet information related to leases was as follows:

Puget Sound Energy
(Dollars in Thousands)	June 30,			December 31,
Operating Leases	2020			2019
Operating lease right-of-use asset	$	179,658		$	183,048
Operating leases liabilities current	16,609			15,862
Operating lease liabilities long-term	170,250			174,327
Total Operating lease liabilities:	$	186,859		$	190,189
Finance Leases
Common Plant	$	1,185		$	1,488
Other current liabilities	616			669
Other deferred credits	519			811
Total finance lease liabilities	$	1,135		$	1,480
Weighted Average Remaining Lease Term
Operating leases	18.93 Years			19.24 Years
Finance leases	2.29 Years			2.76 Years
Weighted Average Discount Rate
Operating leases	3.59		%	3.59		%
Finance leases	2.98		%	2.98		%

The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2020, and December 31, 2019, respectively

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At June 30,	Operating Leases		Finance Leases
2020 (remaining six months)	$	11,653	$	320
2021	23,222		508
2022	22,578		279
2023	22,140		98
2024	21,415		—
Thereafter	162,810		—
Total lease payments	$	263,818	$	1,205
Less imputed interest	(76,959)		(70)
Total	$	186,859	$	1,135

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Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480

(10) Other

Long-Term Debt

On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes (Notes) at an interest rate of 4.1%. The Notes pay interest semi-annually and are due to mature on June 15, 2030. The proceeds from the issuance of the Notes were used to pay $150.0 million under our term loan credit facility, pay $31.6 million of our revolving credit facility, and to redeem $450.0 million in principal amount of the 6.5% senior secured notes due December 15, 2020 and to pay related fees and expenses.

On June 18, 2020, Puget Energy redeemed the $450.0 million senior secured notes due December 15, 2020 and paid related fees and expenses for a total redemption price of $463.2 million. Excluding the repayment of the $450.0 million principal amount and $0.3 million of unamortized debt discount and issuance cost, the extinguishment incurred a $13.5 million loss, which includes $0.4 million of accrued interest expense and is reported in the Puget Energy "Interest Expense" line item as of June 30, 2020.

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, 2019.

Short-Term Debt

During the six months ended June 30, 2020, commercial paper markets were significantly impacted for a period of time due to COVID-19, during which time the Company drew short term funding from its credit facility. Commercial paper markets improved as of June 30, 2020, at which time no amount was drawn under PSE's credit facility and $140.0 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, 2019.

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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, 2019. 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 (COVID-19) was first identified in December 2019, and 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, first and foremost, we have prioritized the health and safety of our customers, employees, and the communities in our service territory implementing a number of changes including not disconnecting customers for non-payment, receiving Washington Commission approval to waive late fees, and filing a motion with the Washington Commission to waive the statutory deadline for the Company’s General Rate Case for up to 60 days, from May 20, 2020, until July 20, 2020, establishing a Crisis-Affected Customer Assistance Program (CACAP), 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 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 gas loads decreased 7.0% and 11.0%, respectively, when comparing weather-adjusted actual to forecast during the fiscal quarter ended June 30, 2020. Residential loads during the quarter ended June 30, 2020, increased 2.6% and 3.1% when comparing weather-adjusted actual to forecast for electric and gas loads, respectively. In contrast, the Company delivered weather-adjusted commercial electric and gas loads of 12.6% and 11.7% lower than forecasted, respectively, during the fiscal quarter ended June 30, 2020. Revenue reductions are partially offset by the effects of decoupling and reduced electric and natural gas supply costs. Decoupling revenue recognized during the quarter was $23.2 million and $3.4 million for electric and natural gas, respectively as compared to $5.9 million and $4.8 million in the same period of 2019 for electric and natural gas, respectively. The Company anticipates that electric and gas loads will continue to be impacted the remainder of 2020 with a partial recovery in the fourth quarter, 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 only 4.3% 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 June 30, 2020. To the extent that the Company incurs material, unexpected expenses associated with the pandemic, such as increased uncollectible accounts receivable, the Company would explore regulatory accounting policies and rate recovery mechanisms to address any negative impacts to financial results.

On March 27, 2020, the U.S. Government enacted the CARES Act, which provides approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 epidemic. 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 $4.7 million as of June 30, 2020.

Further detail regarding the factors and trends affecting performance of the Company during the quarter ended June 30, 2020, 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 2019 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, terrorism, or the impact of civil unrest 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 2020 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. 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.

Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s

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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 also sets natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.

General Rate Case Filing

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 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 which 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 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. As a result of the 2019 GRC outcome, Puget Energy and PSE credit rating metrics will likely be adversely impacted absent other regulatory relief or Corporate mitigation measures otherwise Puget Energy and PSE are at risk of a downgrade to their credit rating. 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 $31 million, or 1.5% and the natural gas increase to $7.7 million, or 1.0%. PSE continues to review the original Commission order including the ramifications of certain tax issues and the order for clarification and expects to file a Compliance Filing to amend electric and natural gas tariffs and, upon approval of this filing, rates will go into effect.

For further details regarding the 2019 GRC filing and credit ratings, see Note 7, "Regulations and Rates" to the consolidated financial statements included in part 1 of this report and "Financing Program: in item 2 of this report, respectively.

Expedited Rate Filing

On November 7, 2018, PSE filed an 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. The settlement requires that PSE pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

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.

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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%. Other outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures. On July 8, 2020, the Washington Commission issued its order in PSE’s GRC, which was consolidated with PSE’s accounting petition filed on December 29, 2017. On July 17, 2020, PSE filed a motion for clarification of several issues in the Washington Commission’s order including issues relating to its accounting petition. On July 31, 2020, PSE received an order granting PSE’s motion for clarification which adjusted certain items within the final order, including treatment of protected excess deferred taxes. PSE is currently reviewing the order granting the motion for clarification.

The Washington Commission approved the following PSE requests to change rates to reflect the new corporate tax rates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
Electric:
May 1, 2018	(3.4)%	$(72.9)
Natural Gas:
May 1, 2018	(2.7)%	$(23.6)

For further details regarding the Washington Commission Tax Deferral Filing, see Note 7, "Regulations and Rates" to the consolidated financial statements included in part 1 of this report.

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). 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 cap, which limits the amount of previously deferred 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 June 30, 2020, 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 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 $2.1 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore an adjustment was booked to 2020 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2020 natural gas decoupling revenue.

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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, 20202	0.2%	$2.0
May 1, 2019	0.9	20.6
May 1, 2018	(1.1)	(25.2)
Natural Gas:
May 1, 2020	(0.5)%	$(4.8)
May 1, 2019	(5.3)	(45.9)
May 1, 2018	1.7	15.9

_______________

¹ For electric and natural gas rates effective May, 1, 2020 there were no excess earnings that impacted the approved revenue change. For electric and natural gas rates effective May, 1, 2019, there were no excess earnings that impacted the approved revenue change. For electric and natural gas rates effective May 1, 2018, the approved revenue change is net of reductions from excess earnings of $10.0 million for electric and $4.9 million for natural gas.

² The 2019 GRC final order lengthened the recovery period to April 2022, however, the rates issued in the final order are not currently in effect.

Electric Rates

Power Cost Adjustment Mechanism

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

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

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

In 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.

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For the six months ended June 30, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $48.8 million of which $19.5 million was apportioned to customers and $1.1 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $46.4 million for the six months ended June 30, 2019, of which $17.3 million was apportioned to customers and accrued $0.2 million interest on the total deferred customer balance. The under recovery in 2020 led to an increase in the PCA deferral, and was a higher under recovery compared to the same period in 2019. The under recovery was due to power costs that were higher than what was collected in the allowed baseline for the six months ended June 30, 2020. Power costs have increased due to a number of factors such as the addition of new resources, increased rates on purchase power agreements and higher transmission costs. Also contributing to the under recovery in 2020 was a reduced load, used to calculate the baseline amount, which was due to warmer than normal weather in the first half of 2020 and to the effects of COVID-19 on energy usage and the economy. Contributing to the under recovery in 2019 were high power prices in the first quarter of 2019 due to cold weather in February and early March of 2019, which drove regional loads and demand for power up resulting in higher prices, and Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices.

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.

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)
July 3, 2020	1.2%	$23.9
July 1, 20191	(1.2)	(24.9)
May 1, 2019	0.1	3.3

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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 (if over $100 thousand) resulting at July 31, 2020 will be 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.

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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, 2020	0.9%	$17.8
May 1, 2019	(0.9)	(17.5)
May 1, 2018	(0.8)	(18.0)

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, 2020	0.07%	$1.4
May 1, 2019	(0.2)	(5.1)
May 1, 2018	(0.1)	(1.3)

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

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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)
October 1, 2017	(0.6)	(80.8)

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, 2020	0.4%	$3.5
May 1, 2019	0.1	1.1

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, 2020	(0.3)%	$(2.8)
May 1, 2019	(0.2)	(1.6)
May 1, 2018	(0.2)	(2.2)

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.

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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, 2019	0.8%	$7.0
November 1, 2018	0.5	5.0

Purchased Gas Adjustment Mechanism

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 rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remains which PSE will request to be amortized in its upcoming 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 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 Enbridge pipeline rupture, 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. Finally, as part of the GRC final order, collection of the $114.4 million commodity deferrals was further lengthened to be collected over three years instead of two.

The following table presents the PGA mechanism balances and activity for six months ended June 30, 2020 and 2019:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30,		At December 31,
PGA receivable balance and activity	2020		2019
PGA receivable beginning balance	$	132,766	$	9,922
Actual natural gas costs	169,697		406,162
Allowed PGA recovery	(217,916)		(289,876)
Interest	2,385		6,558
PGA receivable ending balance	$	86,932	$	132,766

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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, 20192	13.4%	$118.3
May 1, 20191	6.3	54.0
November 1, 2018	(10.9)	(98.4)

_______________

^1.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 will be included in annual PGA filling effective November 1, 2020.

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

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 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 currently under construction in the region by a developer under contract to PSE. The project is fully subscribed and is expected to begin generating power in 2020. Twenty-one customers will receive the anticipated output of the project.

In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase 2 offering will be a blend of the phase 1 wind and a solar project to be built in Washington. Phase 1 customers will receive wind through 2020 and then are expected to receive the blended energy in March 2021. An additional twenty customers will start receiving energy through phase 2 of the program by March 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. 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 will automatically end when all of the funds are disbursed or September 30, 2020 whichever is soonest. 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.

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

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Access to Debt Capital

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

Regulatory Compliance Costs and Expenditures

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

Compliance with these or other future 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 and six months ended June 30, 2019, and 2020.

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 June 30, 2019 and 2020:

______________

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

Three Months Ended June 30, 2019 compared to 2020

Electric Operating Revenue

Electric operating revenues decreased $42.4 million from the prior year primarily due to a decrease in transportation and other revenue of $29.6 million, a decrease in electric retail sales of $28.3 million, and a decrease in other decoupling revenue of $3.8 million; partially offset by an increase in decoupling revenue of $17.3 million and an increase in sales to other utilities of $2.1 million.  These items are discussed in detail below.

•Electric retail sales decreased $28.3 million due to a decrease of $31.9 million from reduced retail electricity usage, or 7.5%, and a decrease in rates of $3.6 million compared to the prior year. The reduction was due to a decrease of commercial and industrial customer usage of 17.5% and 9.2%, respectively, largely driven by business shut downs resulting from COVID-19. This decrease in volumes was partially offset by a 2.4% increase in residential customer usage. Residential usage patterns were affected by customers working from home during Washington's stay-at-home order, an increase in heating degree days of 15.9%, and an increase in retail customers of 1.3% compared to 2019. See Management's Discussion and Analysis, "Regulation and Rates" and "Overview" included in Item 2 of this report for electric rate changes and COVID-19 updates.

•Sales to other utilities increased $2.1 million due to a 75.3% increase in sales volume from an additional 10.9% of combustion turbine (CT) generation as a result of favorable heat rates and increased hydro generation of 60.2%; partially offset by a 27.9% decrease in price.

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•Decoupling revenue increased $17.3 million, primarily due to a combination of a $8.9 million increase in delivery deferral revenues and an $8.3 million increase in PCA fixed cost deferral revenues, driven by a higher allowed rate per customer and decreased actual usage as noted above in the retail revenue section. This resulted in allowed delivery revenues being greater than actual delivery revenues in the current year than in the prior year.

•Other decoupling revenue decreased $3.8 million, primarily due to $2.1 million deferred decoupling revenue that will not be collected within 24 months of the end of 2020. There was no 24 month GAAP reserve in 2019.

•Transportation and other revenue decreased $29.6 million primarily due to a decrease in production tax credit (PTC) deferral revenue of $23.1 million for the re-purpose of the PTCs driven by lower pre-tax book income, a decrease in net wholesale non-core gas sales of $3.2 million, and a decrease in tax reform deferrals in 2020 for revenue subject to refunds of $1.8 million.

Electric Power Costs

Electric power costs decreased $3.4 million primarily due to a $4.6 million decrease of electric generation fuel expenses partially offset by an increase of $1.5 million of purchased electricity costs. These items are discussed in detail below.

•Purchased electricity expense increased $1.5 million primarily due to a 7.8% increase in wholesale electricity purchases; partially offset by a 6.2% decrease in wholesale prices. The increase in purchases was primarily driven by a decrease in contracted resources and non-firm energy of 20.0% and 2.7%, respectively, driving an 10.9% increase in combustion turbine generation.

•Electric generation fuel expense decreased $4.6 million primarily due to a $7.5 million decrease in Colstrip related to the retirement of Units 1 and 2; partially offset by $1.7 million increase in Colstrip 3 & 4 fuel costs and a $1.2 million increase in combustion turbine generation costs primarily driven by a 10.9% increase in production.

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The following chart displays the details of PSE's electric margin changes for the six months ended June 30, 2019 and 2020:

______________

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

Six Months Ended June 30, 2019 compared to 2020

Electric Operating Revenue

Electric operating revenues decreased $172.2 million from the prior year primarily due to a decrease in transportation and other revenues of $116.2 million, a decrease in electric retail sales of $64.4 million, a decrease in sales to other utilities of $7.8 million, and a decrease in other decoupling revenue of $10.7 million; partially offset by decoupling revenue of $26.8 million.  These items are discussed in detail below.

•Electric retail sales decreased $64.4 million due to a decrease of $59.4 million from reduced retail electricity usage, or 5.7%, and a decrease in rates of $5.0 million compared to the prior year. The reduction was due to a decrease of commercial, industrial and residential customer usage of 12.4%, 7.6% and 0.1%, respectively, primarily driven by business shut downs resulting from COVID-19; partially offset by an increase in heating degree days of 1.1% and an increase in retail customers of 1.4% compared to 2019. See Management's Discussion and Analysis, "Regulation and Rates" and "Overview" included in Item 2 of this report for electric rate changes and COVID-19 updates.

•Sales to other utilities decreased $7.8 million due to a 46.8% decrease in price; partially offset by a 46.1% increase in sales volume. During the first quarter of 2019, wholesale prices increased 115.7% due to spot power prices at Mid-Columbia that increased to an 18-year high largely driven by record-breaking natural gas prices. In addition, an increase in volumes from an additional 111.8% of combustion turbine generation as a result of favorable heat rates and increased demand for wholesale market power contributed to the strong revenue in the 2019 period.

•Decoupling revenue increased $26.8 million, primarily due to the combination of a $14.8 million increase in PCA fixed cost deferral revenues and a $12.0 million increase in delivery deferral revenues, driven by a higher allowed rate per customer and decreased actual usage as noted above in the retail revenue section. This resulted in allowed delivery revenues being greater than actual delivery revenues in the current year than in the prior year.

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•Other decoupling revenue decreased $10.7 million, primarily due the following: (i) a $4.3 million decrease year-over-year related to an increase in current year amortization of previous years' decoupling deferrals resulting from higher amortization rates; partially offset by decreased usage; (ii) a $3.5 million decrease related to earnings in excess of allowed ROR. In 2019, earnings in excess of the allowed ROR of $3.5 million was passed back to customers. There were no such collections in 2020; (iii) in 2018 there was $0.8 million of deferred decoupling revenue that could not be collected within 24 months. This was recognized in the first quarter of 2019 as it met the alternative revenue program revenue recognition guidelines. In 2020, $2.1 million deferred decoupling revenue will not be collected within 24 months of the end of 2020 therefore, reserving against the decoupling deferral revenue recognized as discussed above.

•Transportation and other revenue decreased $116.2 million primarily due to a decrease in net wholesale non-core gas sales of $94.7 million and a decrease in PTC deferral revenue of $26.6 million for the re-purpose of the PTCs driven by lower pre-tax book income; partially offset by an increase if tax reform deferrals in 2020 for revenue subject to refunds of $4.8 million. The decrease in net wholesale non-core gas sales was due to a 75% decrease in the average price of the non-core gas sold as well as a 14% decrease in sales volume. The decrease was partially offset by a $37.3 million decrease in the total cost of the non-core gas sold due to a 44% decrease in the average price of non-core gas purchases and the aforementioned decrease in non-core gas sales volume. Prices decreased to a combination of supply changes from high gas production, mild weather, and surplus storage, as well as decreased demand due to business disruptions caused by the COVID-19 pandemic. In contrast, gas prices were high in early 2019 due to the continuing effects of the late 2018 Enbridge pipeline rupture that decreased pipeline capacity in the region, compressor issues at a gas storage facility that limited gas deliverability, and higher than expected loads due to cold weather.

Electric Power Costs

Electric power costs decreased $121.3 million primarily due to a decrease of $103.5 million of purchased electricity costs and $18.2 million of electric generation fuel expenses. These items are discussed in detail below.

•Purchased electricity expense decreased $103.5 million primarily due to a 7.7% decrease in wholesale electricity purchases and a 20.0% decrease in wholesale prices. The decrease in purchases was primarily driven by a decrease in load and a decrease in contracted resources and non-firm energy of 25.5% and 15.5%, respectively, driving an 45.1% increase in combustion turbine generation.

•Electric generation fuel expense decreased $18.2 million primarily due to a $13.7 million decrease in Colstrip related to the retirement of Units 1 and 2 and a $4.3 million decrease in combustion turbine generation costs primarily driven by the cost of natural gas. Natural gas prices trended down in 2020 due to a combination of increased supply from high gas production, and decreased demand from mild winter weather and load pattern changes due to COVID-19 business disruptions from stay at home orders. In contrast, 2019 natural gas prices were high due to the effect of the Enbridge pipeline rupture in late 2018 which led to a decrease in pipeline capacity in the region at the same time that there was compressor issues at a gas storage facility limiting gas deliverability, and higher than expected load due to the cold weather in 2019.

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 June 30, 2019 and 2020:

_______________

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

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Three Months Ended June 30, 2019 compared to 2020

Natural Gas Operating Revenue

Natural gas operating revenue increased $24.2 million primarily due to an increase of $20.9 million in total retail sales, an increase of $3.3 million in other decoupling revenue and an increase of $1.4 million in transportation and other revenue; partially offset by $1.4 million in decoupling revenue. These items are discussed in detail below.

•Natural gas retail sales revenue increased $20.9 million due to an increase in rates of $16.7 million and an increase in natural gas load of 1.2%, or $4.2 million of natural gas sales. Natural gas load increased primarily due to an 11.4% increase in average therms used by residential customers. Residential usage patterns were affected by customers working from home during Washington's stay-at-home order and a 15.9% increase in heating degree days compared to 2019. The increase in residential usage was partially offset by a 17.8% decrease by commercial firm customers, largely driven by business shut downs resulting from COVID-19. See Management's Discussion and Analysis, "Regulation and Rates" and "Overview" included in Item 2 of this report for natural gas rate changes and COVID-19 updates.

•Decoupling revenue decreased $1.4 million, driven by higher actual revenues in the second quarter of 2020 as compared to the same period year over year, while allowed revenues remained constant. The increase in actual revenues is attributable to a higher allowed rate per customer partially offset by decreased natural gas usage, as noted above in the retail revenue section.

•Other decoupling revenue increased $3.3 million, primarily due to higher amortization rates in the three months ended June 30, 2019, compared to the same period in 2020.

Natural Gas Energy Costs

Purchased natural gas expense increased $20.1 million due to an increase in the PGA rates in November 2019 and the addition of two supplemental gas commodity costs amortization rates in 2019 which were added in order to recover the large amount of gas costs that PSE incurred in late 2018 and early 2019 due to the Enbridge pipeline explosion and an increase in natural gas usage of 1.2%.

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The following chart displays the details of PSE's natural gas margin changes for the six months ended June 30, 2019 and 2020:

_______________

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

Six Months Ended June 30, 2019 compared to 2020

Natural Gas Operating Revenue

Natural gas operating revenue increased $90.5 million primarily due to an increase of $63.5 million in total retail sales, an increase of $4.4 million in decoupling revenue, an increase of $21.3 million in other decoupling revenue and an increase of $1.3 million of transportation and other revenue. These items are discussed in detail below.

•Natural gas retail sales revenue increased $63.5 million due to an increase in rates of $76.1 million partially offset by a decrease in natural gas load of 2.9%, or $12.6 million of natural gas sales. Natural gas load decreased primarily due to a 1.2% decrease in average therms used by residential customers and a 8.0% decrease by commercial firm customers primarily driven by business shut downs resulting from COVID-19, partially offset by a 1.1% increase in heating degree days. See Management's Discussion and Analysis, "Regulation and Rates" and "Overview" included in Item 2 of this report for natural gas rate changes and COVID-19 updates.

•Decoupling revenue increased $4.4 million, primarily attributable to an increase in allowed natural gas revenue in 2020 compared to the same period in the previous year, whereas actual revenue remained constant, with increased natural gas rates offset by decreased volumes in 2020.

•Other decoupling revenue increased $21.3 million, primarily due to a $23.5 million decrease in current year amortization of prior year undercollection, which was driven by decreased usage. This is partially offset by a $2.2 million decrease related to earnings in excess of allowed ROR. In 2019, earnings in excess of allowed ROR of $2.2 million was returned to customers and there were no such collections in 2020.

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Natural Gas Energy Costs

Purchased natural gas expense increased $75.6 million due to an increase in the PGA rates in November 2019 and the addition of two supplemental gas commodity costs amortization rates in 2019 which were added in order to recover the large amount of gas costs that PSE incurred in late 2018 and early 2019 due to the Enbridge pipeline explosion; partially offset by a decrease in natural gas usage of 2.9%.

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 June 30, 2019 and 2020:

Three Months Ended June 30, 2019 compared to 2020

Other Operating Expenses

•Net unrealized (gain) loss on derivative instruments increased $42.5 million to a net gain of $12.2 million for the quarter ended June 30, 2020. One of the drivers for the change related to the net settlements of electric and natural gas trades previously recorded as $11.2 million in losses and $0.6 million in gains, respectively. The other driver related to the change is the weighted average forward prices for electric and natural gas. Specifically, forward electric prices increased 3.1% resulting in a $9.4 million gain for electricity. Forward gas prices increased 17.8% resulting in a $22.5 million gain for natural gas.

•Utility operations and maintenance expense decreased $1.3 million primarily due to a decrease in electric steam generation maintenance of $2.8 million primarily related to the retirement of Colstrip 1 & 2, other power generation maintenance of $1.6 million due to reduced wind turbine maintenance at Wild Horse wind facility, and $1.4 million of gas distribution operating expenses due to reduced leak survey expenses in 2020 and delayed spending in operational programs due to business disruptions from COVID-19. This was partially offset by $4.9 million of non-health related employee absence expense driven by COVID-19 stay-at-home mandates.

•Non-utility and other expense increased $5.2 million primarily due to a $7.0 million biogas payment.

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•Depreciation and amortization expense decreased $27.6 million primarily driven by: (i) electric amortization decreased by $30.6 million, primarily driven by a $23.1 million change in PTC amortization due to lower pre-tax book income and $4.6 million in amortization for the regulatory liability associated with revised power cost Schedule 95A effective July 1, 2019; (ii) common amortization decreased by $1.4 million or 6.9% from 2019. The decrease is primarily driven by the $9.8 in deferral treatment of software amortization effective May 1, 2019 as submitted to the Washington Commission offset by net additions of computer software of $50.6 million. Additionally, the decreases were partially offset by (iii) electric distribution depreciation increased a net of $2.2 million or 6.4% from 2019. The increase is primarily due to $130.0 million in net additions of electrical distribution assets; and (iv) natural gas distribution depreciation increased by $2.2 million or 7.8% from 2019. The increase is primarily due to $245.3 million in net additions in natural gas distribution assets.

•Taxes other than income taxes decreased $1.2 million primarily due to a decrease of $1.3 million related to the property tax tracker due to load.

Other Income, Interest Expense and Income Tax Expense 

•Other income/expense increased $6.1 million primarily due to $6.3 million of SmartBurn plant investment at Colstrip 3& 4 which recovery was disallowed per Washington Commission Order UE-190529.

•Interest expense increased $2.2 million due to $3.7 million of interest expense on the $450.0 million senior note issued in 2019, PTC interest expense of $1.4 million in 2020, partially offset by a decrease of $2.5 million of other interest expense attributed to lower commercial paper borrowing in 2020.

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The following chart displays the details of PSE's operating expenses and other income (deductions) for the six months ended June 30, 2019 and 2020:

Six Months Ended June 30, 2019 compared to 2020

Other Operating Expenses

•Net unrealized (gain) loss on derivative instruments decreased $21.2 million to a net loss of $36.4 million for the six months ended June 30, 2020. One of the drivers for the change related to the net settlements of electric and natural gas trades previously recorded as $55.5 million and $16.6 million in losses, respectively. The other driver related to the change is the weighted average forward prices for electric and natural gas. Specifically, forward electric prices decreased 23.9% resulting in a $74.0 million loss for electricity. Forward gas prices decreased 6.9% resulting in a $19.3 million loss for natural gas.

•Utility operations and maintenance expense decreased $4.3 million primarily due to steam generation maintenance of $4.2 primarily related to the retirement of Colstrip 1 & 2, other power generation maintenance of $1.2 million due to reduced wind turbine maintenance at Wild Horse wind facility, $1.9 million of gas distribution operating expenses due to reduced leak survey expenses in 2020 and delayed spending in operational programs due to COVID-19. Additionally, the following expenses have decreased due to a change in operations from stay at home mandates and other business disruptions from COVID-19: $2.3 million of injuries and damages expense, $1.9 million of maintenance to general plant, $1.0 million in rent expense and $1.0 million of outside services expense. These expenses were partially offset by an increase in other power generation expenses of $1.8 million due to increased CT operations, $5.4 million of non-health related employee absence expense driven by COVID-19 stay-at-home mandates, and $1.6 million of customer assistance expenses.

•Non-utility and other expense increased $4.7 million primarily due to a $7.0 million biogas payment, an increase in pension plan costs of $4.2 million; partially offset by a decrease in biogas purchase expense of $3.3 million and a decrease in long term incentive plan costs of $4.2 million.

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•Depreciation and amortization expense decreased $49.4 million primarily driven by: (i) electric amortization decreased by $45.3 million from 2019. This decrease is primarily driven by the $26.6 million change in PTC amortization and the $11.0 million in amortization for the regulatory liability associated with revised power cost Schedule 95A effective July 1, 2019; (ii) conservation amortization decreased by $5.6 million; (iii) common amortization decreased by $6.1 million or 14.0% from 2019. The decrease is primarily driven by the $19.4 million in deferral treatment of software amortization effective May 1, 2019 as submitted to the Washington Commission offset by net additions of computer software of $50.6 million. Additionally, the decreases were partially offset by (iv) electric distribution depreciation increased a net of $4.5 million or 6.6% from 2019. The increase is primarily due to $130.0 million in net additions of electric distribution assets; and (v) natural gas distribution depreciation increased by $4.2 million or 7.6% from 2019. The increase is primarily due to $245.3 million in net additions in natural gas distribution assets.

•Taxes other than income taxes decreased $4.4 million primarily due to a decrease of $3.8 million related to the property tax tracker due to load.

Interest and Income Tax Expense 

•Other income/expense increased $6.0 million primarily due to $6.3 million of SmartBurn plant investment at Colstrip 3& 4 which recovery was disallowed per Washington Commission Order UE-190529.

•Interest expense increased $2.5 million due to $7.3 million of interest expense on the $450.0 million senior note issued in 2019, PTC interest expense of $2.8 million in 2020, partially offset by a decrease of $5.0 million of other interest expense attributed to lower commercial paper borrowing in 2020.

•Income tax expense decreased $5.9 million primarily driven by a decrease in pre-tax income.

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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 June 30, 2019 and 2020, is as follows:

Three Months Ended June 30, 2019 compared to 2020

Summary Results of Operation

Puget Energy’s net income increased for the three months ended June 30, 2020, by $9.7 million primarily due to an increase in PSE's net income of $23.4 million; partially offset by an increase in interest expense of $15.6 million compared to the same period in the prior year.

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Puget Energy

Puget Energy's net income (loss) for the six months ended June 30, 2019 and 2020, is as follows:

Six Months Ended June 30, 2019 compared to 2020

Summary Results of Operation

Puget Energy’s net income decreased for the six months ended June 30, 2020, by $27.5 million primarily due to a decrease in PSE's net income of $12.6 million and an increase in interest expense of $16.8 million compared to the same period in the prior year.

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, 2019, during the six months ended June 30, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $935.3 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, 2019.

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The following are the Company's aggregate availability under commercial commitments as of June 30, 2020:

Puget Energy and Puget Sound Energy	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total		2020		2021-2022		2023-2024		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	800,000		—		—		800,000		—
Less: Inter-company short-term debt elimination	(30,000)		—		—		—		(30,000)
Total Puget Energy commercial commitments	$	1,600,000	$	—	$	—	$	1,600,000	$	—

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

Off-Balance Sheet Arrangements

As of June 30, 2020, 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

PSE’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 $46.6 million compared to forecasted amounts for the six months ended June 30, 2020. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $428.8 million for the six months ended June 30, 2020. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Millions)	2020	2021	2022
Total energy delivery, technology and facilities expenditures	$877.1	$1,031.1	$1,023.7

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	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		Change
Net income	$	126,358	$	138,977	$	(12,619)
Non-cash items1	365,227		377,305		(12,078)
Changes in cash flow resulting from working capital2	87,782		(1,206)		88,988
Regulatory assets and liabilities	(71,204)		(19,061)		(52,143)
Purchased gas adjustment	45,833		(144,917)		190,750
Other non-current assets and liabilities3	(5,073)		(9,822)		4,749
Net cash provided by operating activities	$	548,923	$	341,276	$	207,647

_______________

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.

Six Months Ended June 30, 2020 compared to 2019

Cash generated from operations for the six months ended June 30, 2020 increased by $207.6 million including a net income decrease of $12.6 million. The following are significant factors that impacted PSE's cash flows from operations:

•Cash flow adjustments resulting from non-cash items decreased $12.1 million primarily due to decreases in depreciation and amortization of $43.8 million, amortization of TCJA Over Collection of $13.1 million, conservation amortization of $5.6 million and equity allowance for funds used during construction (AFUDC-Equity) of $5.1 million, offset by a $26.6 million change in production tax credit utilization, a $21.2 million change from a net unrealized loss on derivative instruments of $15.1 million to a net unrealized loss on derivative instruments of $36.4 million, a loss of $6.3 million due to writing off Smart Burn project at Colstrip, deferred income taxes of $1.3 million. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.

•Cash flows resulting from changes in working capital increased $89.0 million primarily due to decreased cash outflow in Accounts payable of $127.0 million, which was mainly due to 2019 includes payments of significant power and natural gas costs accrued at December 31, 2018 that were paid in 2019. The decrease of cash outflow in account payable was partially offset by $19.8 million decrease of cash inflow in account receivable and $12.1 million increase of cash outflow paid for materials and supplies.

•Cash flow resulting from purchased gas adjustment (long-term) increased $190.8 million. Affected by three events experienced by PSE in 2019 winter: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility, actual natural gas cost went above natural gas baseline rates in the PGA mechanism, caused total purchased gas adjustment receivable increased from $9.9 million to $144.9 million during the first six months of 2019, led to $135.0 million cash outflow. In contrast, both price of natural gas and actual gas consumption decreased in the first six months of 2020. Combined with higher PGA rates taking effect on May 1, 2019, total purchase gas adjustment receivable decreased from $132.8 million to $86.9 million in the first six months of 2020, resulting in a $45.8 million cash inflow. A change from $135.0 million cash outflow to $45.8 million cash inflow led to an increase of cash flow of $180.8 million, which includes an increase in PGA long-term of $190.8 million and a decrease in PGA short-term of $10.0 million.

•Cash flow resulting from changes in regulatory assets and liabilities decreased $52.1 million in the same period year over year primarily due to a $31.2 million increase in decoupling deferrals and a $10.6 million decrease in cash collections of previously deferred amounts.

•Cash flow resulting from changes in non-current assets and liabilities increased $4.7 million primarily due to the Company deferred payroll taxes totaling $4.7 million as of June 30, 2020. The deferral is a result of the tax modifications included in the CARES Act, which was enacted on March 27, 2020.

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Puget Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		Change
Net income	$	(54,655)	$	(39,775)	$	(14,880)
Non-cash items1	10,392		(1,460)		11,852
Changes in cash flow resulting from working capital2	(2,293)		(5,914)		3,621
Regulatory assets and liabilities	(64)		—		(64)
Other non-current assets and liabilities3	(6,041)		(3,416)		(2,625)
Net cash provided by operating activities	$	(52,661)	$	(50,565)	$	(2,096)

_______________

¹ Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, (Gain) or loss on extinguishment of debt, 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.

Six Months Ended June 30, 2020 compared to 2019

Cash generated from operations for the six months ended June 30, 2020, in addition to the changes discussed at PSE above, decreased by $2.1 million compared to the same period in 2019, which includes a net income decrease of $14.9 million.  The remaining change was primarily impacted by the factors explained below:

•Non-cash items increased $11.9 million primarily caused by the cash outflow of $13.5 million due to extinguishment of debt reflected in Financing activities, which partially offset by increased cash outflow of $1.8 million due to changes in deferred taxes.

•Cash flow resulting from working capital increased $3.6 million primarily due to changes in eliminations of PSE's intercompany account receivable and account payable balances with Puget LNG and PE.

•Cash flow resulting from Other non-current assets and liabilities decreased $2.6 million primarily due to change of the valuation of pension liability compared to the prior year.

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, the receipt of the Washington Commission approval to waive late fees, the 2019 GRC order issued by the Washington Commission on July 8, 2020, will impact future cash receipts.

As a result of the 2019 GRC outcome, Puget Energy and PSE's credit rating metrics will likely be adversely impacted absent other regulatory relief or Corporate mitigation measures. In response to the order, Moody's released an issuer comment stating the GRC outcome was credit negative but took no formal action away from credit stable. S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome and Fitch affirmed Puget Energy and PSE as a negative outlook. A credit downgrade would lower Puget Energy from investment grade to non-investment grade and PSE would remain at investment grade. Additionally, a credit 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 facility. The increase in cost of borrowing could impact Puget Energy and PSE's liquidity and capital resources which could have a material adverse effect on their results of operations 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

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clauses. A credit rating decrease for PSE could result in increased cash collateral required for commodity contracts, which would adversely affect PSE's liquidity.

Commercial paper markets were significantly impacted for a period of time due to COVID-19, which limited commercial paper borrowings and alternatively 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 removed its cash reserve requirement. Evolving factors that we cannot accurately predict, including the duration and scope of the pandemic, and any relevant governmental, business and customers’ actions that have been and continue to be taken in response to the pandemic, could negatively impact the Company’s liquidity.

Puget Sound Energy

Credit Facility

As of June 30, 2020, 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 June 30, 2020, 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 June 30, 2020, $0.0 million was drawn under PSE's credit facility and $140.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.8 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 June 30, 2020, 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 June 30, 2020, PSE could issue:

•Approximately $2.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $3.3 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 June 30, 2020; and

•Approximately $714.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $1.2 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 June 30, 2020.

At June 30, 2020, PSE had approximately $7.7 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

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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 June 30, 2020, approximately $969.5 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 48.9% at June 30, 2020, and the EBITDA to interest expense was 5.1 to 1.0 for the twelve months ended June 30, 2020.

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 June 30, 2020, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Long Term Debt

PSE had no new long-term debt activities in the six months ended June 30, 2020. 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, 2019.

Puget Energy

Credit Facility

At June 30, 2020, 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 June 30, 2020, there was no amount 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 June 30, 2020, Puget Energy was in compliance with all applicable covenants.

Long-Term Debt

On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes (Notes) at an interest rate of 4.1%. The Notes pay interest semi-annually and are due to mature on June 15, 2030. The proceeds from the issuance of the Notes were used to pay $150.0 million under our term loan credit facility, pay $31.6 million of our revolving credit facility, and to redeem $450.0 million in principal amount of our 6.5% senior secured notes due December 15, 2020 and to pay related fees and expenses.

On June 18, 2020, Puget Energy redeemed the $450.0 million senior secured notes due December 15, 2020 and paid related fees and expenses for a total redemption price of $463.2 million. Excluding the repayment of the $450.0 million principal amount and $0.3 million of unamortized debt discount and issuance cost, the extinguishment incurred a $13.5 million loss, which includes $0.4 million of accrued interest expense and is reported in the Puget Energy "Interest Expense" line item as of June 30, 2020.

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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, 2019.

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 3.3 to 1.0 for the twelve months ended June 30, 2020.

At June 30, 2020, 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 Power Purchase Agreements (PPAs) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.

IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather adjusted sales revenue to customers from the previous year. If relying on the 2% threshold for alternative compliance, 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 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 2017 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. On July 8, 2020, the Washington Commission issued its final order in the 2019 GRC which further shortened the depreciable life for Colstrip 3 and 4 to December 31, 2025 to align with the requirements of the Clean Energy Transformation Act.

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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 agreement, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. PSE filed an application seeking approval of the sale from the Washington Commission on February 20, 2020. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has 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. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. Both the Washington Commission and the Montana Public Service Commission have placed the respective procedural calendars on hold until the terms of the deal can be updated for the additional Colstrip owner’s contractual purchase right and supplemental testimony can be filed. The original purchase agreement is written such that the purchase must close by December 31, 2020. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2019, and June 30, 2020, and determined that these criteria were not met. 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. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. Compliance plans under ACE are due July 2022, and compliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations pending the outcome of the proposed Colstrip Unit 4 sale to NorthWestern Energy.

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Washington Clean Air Rule

The 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 Thurston County Superior Court. In March 2018, the Thurston County Superior Court 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. Ecology and the four parties asked Thurston County to stay this case until the 2020 Washington State legislative session concluded and now 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 an 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 is currently under construction. Pursuant to the Washington 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, $224.5 million of construction work in progress and $0.7 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 June 30, 2020. 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.

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, 2019.

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

71

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 June 30, 2020, 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

During 2018, Puget Energy implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended June 30, 2020 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2020, 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.

72

Changes in Internal Control over Financial Reporting

During 2018, PSE implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.

There have been no changes in PSE’s internal control over financial reporting during the quarter ended June 30, 2020 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 June 30, 2020.  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.

Item 1A.  Risk Factors

The following represents a material change in our risk factors from those disclosed in Part 1, Item 1A of our Form 10-K for the year ended December 31, 2019.

PSE faces risks related to the COVID-19 pandemic and other outbreaks that could have a material adverse impact on our business and results of operations. Business disruptions arising from stay at home mandates due to the COVID-19 pandemic has adversely affected economic activity within Washington State and the United States of America. We cannot predict the degree that the continued spread of COVID-19 and efforts to contain the virus (including, but not limited to, voluntary and mandatory quarantines, restrictions on travel, limiting gatherings of people, and reduced operations and extended closures of many businesses and institutions) could materially impact our results of operations, financial condition and ongoing operations. The impacts include but are not limited to:

•impacting customer demand for electricity and natural gas by our customers, particularly from commercial and industrial customers;

•reducing the availability and productivity of our employees;

•causing us to experience an increase in costs as a result of our emergency measures, delayed payments from our customers and uncollectible accounts;

•causing delays and disruptions in the availability of and timely delivery of materials and components used in our operations;

•causing a deterioration in our financial metrics or the business environment that impacts our credit ratings;

•causing significant disruption in the financial markets which could have a negative impact on our ability to access capital in the future and cost of capital;

•resulting in our inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding the ratio of total debt to total capitalization; and

•disrupting our ability to meet customer requirements and potentially significantly increase response costs.

Item 6.   Exhibits

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

73

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).
4.1	Fifth Supplemental Indenture dated May 19, 2020 relating to Puget Energy’s 4.100% Senior Secured Notes due 2030 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K Filed May 19, 2020, Commission File No. 1-16305).
4.2	Registration Rights Agreement, dated as of May 19, 2020, among Puget Energy, Inc., Barclays Capital Inc., J.P. Morgan Securities LLC and Mizuho Securities USA LLC, as representatives of the several initial purchasers party thereto (incorporated herein by reference to Exhibit 4.6 to Puget Energy’s Current Report on Form 8-K Filed May 19, 2020, Commission File No. 1-16305).
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 June 30, 2020 filed on August 05, 2020 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.

74

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:	August 5, 2020

75

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:	August 5, 2020
/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:	August 5, 2020
/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:	August 5, 2020
/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:	August 5, 2020
/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 June 30, 2020 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:	August 5, 2020
/s/ Mary E. Kipp
Mary E. Kipp
President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period ended June 30, 2020 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:	August 5, 2020
/s/ Daniel A. Doyle
Daniel A. Doyle
Senior Vice President and Chief Financial Officer

XML

Document And Entity Information	6 Months Ended
	Jun. 30, 2020 shares
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2020
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		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Operating revenue:
Electric	$ 468,366	$ 510,742	$ 1,137,456	$ 1,309,670
Natural gas	177,609	153,457	548,640	458,125
Other	5,704	6,731	11,713	17,974
Total operating revenue	651,679	670,930	1,697,809	1,785,769
Energy costs:
Purchased electricity	125,487	124,001	291,229	394,703
Electric generation fuel	32,974	37,601	96,598	114,800
Residential exchange	(16,167)	(15,972)	(40,801)	(41,135)
Purchased natural gas	61,257	41,116	216,133	140,503
Unrealized (gain) loss on derivative instruments, net	(12,162)	30,332	36,379	15,145
Utility operations and maintenance	148,120	149,424	303,042	307,379
Non-utility expense and other	15,841	10,620	28,803	24,377
Depreciation & amortization	136,865	164,715	301,681	345,412
Conservation amortization	20,321	20,029	47,714	53,315
Taxes other than income taxes	68,793	69,949	174,297	178,695
Total operating expenses	581,329	631,815	1,455,075	1,533,194
Operating income(loss)	70,350	39,115	242,734	252,575
Other income (expense):
Other income	16,576	15,439	30,635	29,003
Other expense	(8,468)	(1,825)	(10,750)	(3,601)
Interest charges:
AFUDC	3,914	3,570	7,557	6,920
Interest expense	(106,793)	(87,770)	(195,677)	(175,786)
Income (loss) before income taxes	(24,421)	(31,471)	74,499	109,111
Income tax (benefit) expense	(1,188)	1,481	2,796	9,909
Net income (loss)	(23,233)	(32,952)	71,703	99,202
Subsidiaries [Member]
Operating revenue:
Electric	468,366	510,742	1,137,456	1,309,670
Natural gas	177,609	153,457	548,640	458,125
Other	5,704	6,731	11,713	17,974
Total operating revenue	651,679	670,930	1,697,809	1,785,769
Energy costs:
Purchased electricity	125,487	124,001	291,229	394,703
Electric generation fuel	32,974	37,601	96,598	114,800
Residential exchange	(16,167)	(15,972)	(40,801)	(41,135)
Purchased natural gas	61,257	41,116	216,133	140,503
Unrealized (gain) loss on derivative instruments, net	(12,162)	30,332	36,379	15,145
Utility operations and maintenance	148,120	149,424	303,042	307,379
Non-utility expense and other	15,048	9,978	27,783	23,055
Depreciation & amortization	136,816	164,692	301,587	345,370
Conservation amortization	20,321	20,029	47,714	53,315
Taxes other than income taxes	68,793	69,949	174,297	178,695
Total operating expenses	580,487	631,150	1,453,961	1,531,830
Operating income(loss)	71,192	39,780	243,848	253,939
Other income (expense):
Other income	12,862	12,412	24,145	22,961
Other expense	(8,468)	(1,825)	(10,750)	(3,601)
Interest charges:
AFUDC	3,914	3,570	7,557	6,920
Interest expense	(62,464)	(59,935)	(123,178)	(120,085)
Income (loss) before income taxes	17,036	(5,998)	141,622	160,134
Income tax (benefit) expense	1,999	2,327	15,264	21,157
Net income (loss)	$ 15,037	$ (8,325)	$ 126,358	$ 138,977

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Net Income (loss)	$ (23,233)	$ (32,952)	$ 71,703	$ 99,202
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,630	91	6,800	183
Other comprehensive income (loss)	1,630	91	6,800	183
Comprehensive income (loss)	(21,603)	(32,861)	78,503	99,385
Amortization of right-of-use asset	152	124	304	282
Interest on lease liabilities	9	10	19	19
FInance Lease, Cost	161	134	323	301
Operating lease cost	5,669	5,223	11,149	10,007
Net unrealized gain (loss) from pension and postretirement plans, net of tax	433	25	1,806	50
Subsidiaries [Member]
Net Income (loss)	15,037	(8,325)	126,358	138,977
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	3,860	2,512	11,570	5,022
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	96	96	192	192
Other comprehensive income (loss)	3,956	2,608	11,762	5,214
Comprehensive income (loss)	18,993	(5,717)	138,120	144,191
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax	25	26	51	51
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 1,025	$ 667	$ 3,072	$ 1,335

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 433	$ 25	$ 1,806	$ 50
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,025	667	3,072	1,335
Amortization of treasury interest rate swaps to earnings, net of tax	$ 25	$ 26	$ 51	$ 51

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Utility Plant [Abstract]
Electric plant	$ 8,999,303	$ 8,811,889
Natural gas plant	4,078,221	3,916,040
Common plant	1,093,033	1,096,649
Less: Accumulated depreciation and amortization	(3,460,359)	(3,236,240)
Net utility plant	10,710,198	10,588,338
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	313,557	286,975
Total other property and investments	1,970,070	1,943,488
Current assets:
Cash and cash equivalents	27,434	45,259
Restricted cash	28,777	20,887
Accounts Receivable, after Allowance for Credit Loss, Current	235,712	316,352
Unbilled revenue	116,225	224,657
Materials and supplies, at average cost	131,521	115,684
Fuel and natural gas inventory, at average cost	51,290	52,083
Unrealized gain on derivative instruments	27,419	23,626
Prepaid expense and other	27,675	27,504
Power contract acquisition adjustment gain	10,865	9,067
Total current assets	656,918	835,119
Other long-term and regulatory assets:
Power cost adjustment mechanism	62,269	41,745
Regulatory assets related to power contracts	12,678	14,146
Other regulatory assets	683,345	673,021
Unrealized gain on derivative instruments	7,124	7,682
Power contract acquisition adjustment gain	90,978	147,530
Operating lease right-of-use asset	179,658	183,048
Other	87,840	92,980
Total other long-term and regulatory assets	1,210,825	1,292,918
Total assets	14,548,011	14,659,863
Capitalization
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	802,130	775,491
Accumulated other comprehensive income (loss), net of tax	(77,349)	(84,149)
Total common shareholder’s equity	4,033,738	4,000,299
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	2,234,000	1,758,100
Debt discount issuance costs and other	(211,330)	(211,635)
Total long-term debt	6,396,530	5,920,325
Total capitalization	10,430,268	9,920,624
Current liabilities:
Accounts payable	270,947	325,913
Short-term debt	140,000	176,000
Accrued expenses:
Taxes	93,973	99,979
Salaries and wages	41,395	50,091
Interest	74,927	74,855
Unrealized loss on derivative instruments	29,769	13,428
Power contract acquisition adjustment loss	2,197	2,418
Operating lease liabilities	16,609	15,862
Other	83,714	107,809
Total current liabilities	755,943	1,318,767
Other long-term and regulatory liabilities:
Unrealized loss on derivative instruments	34,172	12,693
Regulatory liabilities	719,587	730,879
Regulatory liability for deferred income taxes	931,063	946,179
Regulatory liabilities related to power contracts	101,843	156,597
Power contract acquisition adjustment loss	10,481	11,728
Operating lease liabilities	170,250	174,327
Total long-term and regulatory liabilities	3,361,800	3,420,472
Commitments and Contingencies
Total capitalization and liabilities	14,548,011	14,659,863
purchase gas adjustment, long-term	86,933	132,766
Long-term Debt, Current Maturities	2,412	452,412
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	720,680	591,199
Allowance for doubtful accounts	$ 10,899	$ 8,294
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Other Deferred Credits	$ 551,020	$ 563,349
Deferred Tax and Other Liabilities, Noncurrent	843,384	824,720
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,846,456	10,671,328
Natural gas plant	4,638,729	4,478,048
Common plant	1,117,680	1,121,568
Less: Accumulated depreciation and amortization	(5,892,667)	(5,682,606)
Net utility plant	10,710,198	10,588,338
Other property and investments:
Other property and investments	82,129	81,112
Total other property and investments	82,129	81,112
Current assets:
Cash and cash equivalents	26,930	44,004
Restricted cash	28,777	20,887
Accounts Receivable, after Allowance for Credit Loss, Current	256,168	319,229
Unbilled revenue	116,225	224,657
Materials and supplies, at average cost	131,521	115,684
Fuel and natural gas inventory, at average cost	50,089	50,818
Unrealized gain on derivative instruments	27,419	23,626
Prepaid expense and other	27,675	27,504
Total current assets	664,804	826,409
Other long-term and regulatory assets:
Power cost adjustment mechanism	62,269	41,745
Other regulatory assets	683,345	673,021
Unrealized gain on derivative instruments	7,124	7,682
Operating lease right-of-use asset	179,658	183,048
Other	86,052	90,924
Total other long-term and regulatory assets	1,105,381	1,129,186
Total assets	12,562,512	12,625,045
Capitalization
Common stock	859	859
Additional paid-in capital	3,485,105	3,485,105
Retained earnings	777,742	751,193
Accumulated other comprehensive income (loss), net of tax	(176,715)	(188,477)
Total common shareholder’s equity	4,086,991	4,048,680
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	(36,770)	(37,718)
Total long-term debt	4,337,090	4,336,142
Total capitalization	8,424,081	8,384,822
Current liabilities:
Accounts payable	272,570	325,980
Short-term debt	140,000	176,000
Accrued expenses:
Taxes	97,917	99,977
Salaries and wages	41,395	50,091
Interest	48,087	48,917
Unrealized loss on derivative instruments	29,769	13,428
Operating lease liabilities	16,609	15,862
Other	83,714	107,809
Total current liabilities	732,473	840,476
Other long-term and regulatory liabilities:
Unrealized loss on derivative instruments	34,172	12,693
Regulatory liabilities	718,386	729,614
Regulatory liability for deferred income taxes	931,814	946,936
Operating lease liabilities	170,250	174,327
Total long-term and regulatory liabilities	3,405,958	3,399,747
Commitments and Contingencies
Total capitalization and liabilities	12,562,512	12,625,045
purchase gas adjustment, long-term	86,933	132,766
Long-term Debt, Current Maturities	2,412	2,412
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	720,680	591,199
Allowance for doubtful accounts	$ 10,899	$ 8,294
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
Other Deferred Credits	$ 545,657	$ 559,014
Deferred Tax and Other Liabilities, Noncurrent	$ 1,005,679	$ 977,163

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
ASSETS
Construction work in progress	$ 720,680	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 10,899	$ 8,294
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 720,680	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 10,899	$ 8,294
Common shareholder’s equity:
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

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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, 2018		200					85,903,791
Beginning Balance at Dec. 31, 2018	$ 3,860,758	$ 0	$ 3,308,957	$ 629,003	$ (77,202)	$ 3,707,924	$ 859	$ 3,275,105	$ 622,844	$ (190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	132,154			132,154		147,302			147,302
Common stock dividend paid	(35,994)			(35,994)		(64,604)			(64,604)
Other comprehensive income (loss)	92				92	2,606				2,606
Ending Balance (in shares) at Mar. 31, 2019		200					85,903,791
Ending Balance at Mar. 31, 2019	3,957,010	$ 0	3,308,957	725,163	(77,110)	3,793,228	$ 859	3,275,105	705,542	(188,278)
Beginning Balance (in shares) at Dec. 31, 2018		200					85,903,791
Beginning Balance at Dec. 31, 2018	3,860,758	$ 0	3,308,957	629,003	(77,202)	3,707,924	$ 859	3,275,105	622,844	(190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	99,202					138,977
Other comprehensive income (loss)	183					5,214
Ending Balance (in shares) at Jun. 30, 2019		200					85,903,791
Ending Balance at Jun. 30, 2019	3,924,066	$ 0	3,308,957	692,128	(77,019)	3,768,127	$ 859	3,275,105	677,833	(185,670)
Beginning Balance (in shares) at Mar. 31, 2019		200					85,903,791
Beginning Balance at Mar. 31, 2019	3,957,010	$ 0	3,308,957	725,163	(77,110)	3,793,228	$ 859	3,275,105	705,542	(188,278)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(32,952)			(32,952)		(8,325)			(8,325)
Common stock dividend paid	(83)			(83)		(19,384)			(19,384)
Other comprehensive income (loss)	91				91	2,608				2,608
Ending Balance (in shares) at Jun. 30, 2019		200					85,903,791
Ending Balance at Jun. 30, 2019	$ 3,924,066	$ 0	3,308,957	692,128	(77,019)	$ 3,768,127	$ 859	3,275,105	677,833	(185,670)
Beginning Balance (in shares) at Dec. 31, 2019	200	200				85,903,791	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)	94,936			94,936		111,321			111,321
Common stock dividend paid	(22,645)			(22,645)		(53,794)			(53,794)
Other comprehensive income (loss)	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, 2019	200	200				85,903,791	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)	71,703					126,358
Other comprehensive income (loss)	$ 6,800					$ 11,762
Ending Balance (in shares) at Jun. 30, 2020	200	200				85,903,791	85,903,791
Ending Balance at Jun. 30, 2020	$ 4,033,738	$ 0	3,308,957	802,130	(77,349)	$ 4,086,991	$ 859	3,485,105	777,742	(176,715)
Beginning Balance (in shares) at Mar. 31, 2020		200					85,903,791
Beginning 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)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(23,233)			(23,233)		15,037			15,037
Common stock dividend paid	(22,419)			(22,419)		(46,015)			(46,015)
Other comprehensive income (loss)	$ 1,630				1,630	$ 3,956				3,956
Ending Balance (in shares) at Jun. 30, 2020	200	200				85,903,791	85,903,791
Ending Balance at Jun. 30, 2020	$ 4,033,738	$ 0	$ 3,308,957	$ 802,130	$ (77,349)	$ 4,086,991	$ 859	$ 3,485,105	$ 777,742	$ (176,715)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Operating activities:
Net Income (loss)	$ (23,233)	$ 94,936	$ (32,952)	$ 132,154	$ 71,703	$ 99,202
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization	136,865		164,715		301,681	345,412
Conservation amortization	20,321		20,029		47,714	53,315
Deferred income taxes and tax credits, net					1,741	2,248
Net unrealized (gain) loss on derivative instruments					36,379	15,145
Gain (Loss) on Extinguishment of Debt					13,546	0
AFUDC - equity					(11,668)	(6,591)
Production tax credit utilization					(14,470)	(41,111)
Other non-cash					696	7,427
Regulatory assets and liabilities					(71,268)	(19,061)
increase (decrease) in purchased gas					45,833	(144,917)
Other long term assets and liabilities					(11,114)	(13,238)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue					189,072	203,174
Materials and supplies					(15,837)	(3,769)
Fuel and natural gas inventory					793	(5,338)
Prepayments and other					(171)	(85)
Purchased gas adjustment					0	9,921
Accounts payable					(54,136)	(179,533)
Taxes payable					(6,006)	(20,798)
Other					(28,226)	(10,692)
Net cash provided by (used in) operating activities					496,262	290,711
Investing activities:
Construction expenditures - excluding equity AFUDC					(438,477)	(470,335)
Other					104	(3,977)
Net cash provided by (used in) investing activities					(438,373)	(474,312)
Financing activities:
Change in short-term debt, net					(36,000)	160,703
Dividends paid					(45,064)	(36,077)
Proceeds from long-term debt and bonds issued					644,690	20,000
Repayments of Debt					(174,100)	0
Redemption of bonds and notes					(450,000)	0
Other					(7,350)	7,411
Net cash provided by (used in) financing activities					(67,824)	152,037
Net increase (decrease) in cash, cash equivalents, and restricted cash					(9,935)	(31,564)
Cash, cash equivalents, and restricted cash at beginning of period		66,146		55,562	66,146	55,562	$ 55,562
Cash, cash equivalents, and restricted cash at end of period	56,211		23,998		56,211	23,998	66,146
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)					169,832	165,863
Cash payments (refunds) for income taxes					0	5,376
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows					57,498	73,757
Increase (Decrease) in Regulatory Assets and Liabilities					0	(47,516)
Subsidiaries [Member]
Operating activities:
Net Income (loss)	15,037	111,321	(8,325)	147,302	126,358	138,977
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization	136,816		164,692		301,587	345,370
Conservation amortization	20,321		20,029		47,714	53,315
Deferred income taxes and tax credits, net					10,267	8,967
Net unrealized (gain) loss on derivative instruments					36,379	15,145
AFUDC - equity					(11,668)	(6,591)
Production tax credit utilization					(14,470)	(41,111)
Other non-cash					(4,582)	2,210
Regulatory assets and liabilities					(71,204)	(19,061)
increase (decrease) in purchased gas					45,833	(144,917)
Other long term assets and liabilities					(5,073)	(9,822)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue					186,425	206,228
Materials and supplies					(15,837)	(3,769)
Fuel and natural gas inventory					729	(5,338)
Prepayments and other					(171)	(85)
Purchased gas adjustment					0	9,921
Accounts payable					(52,580)	(179,591)
Taxes payable					(2,060)	(20,679)
Other					(28,724)	(7,893)
Net cash provided by (used in) operating activities					548,923	341,276
Investing activities:
Construction expenditures - excluding equity AFUDC					(428,775)	(451,215)
Other					104	(3,977)
Net cash provided by (used in) investing activities					(428,671)	(455,192)
Financing activities:
Change in short-term debt, net					(36,000)	160,703
Dividends paid					(99,809)	(83,988)
Other					6,373	7,410
Net cash provided by (used in) financing activities					(129,436)	84,125
Net increase (decrease) in cash, cash equivalents, and restricted cash					(9,184)	(29,791)
Cash, cash equivalents, and restricted cash at beginning of period		$ 64,891		$ 53,493	64,891	53,493	53,493
Cash, cash equivalents, and restricted cash at end of period	$ 55,707		$ 23,702		55,707	23,702	$ 64,891
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)					114,027	112,058
Cash payments (refunds) for income taxes					0	9,784
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows					57,498	73,757
Increase (Decrease) in Regulatory Assets and Liabilities					$ 0	$ (47,516)

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Summary of Consolidation and Significant Accounting Policy

3 Months Ended

Jun. 30, 2020

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, (Puget LNG) 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

On January 1, 2020, the Company adopted ASU 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables.

The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial.

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 following table presents the activity in the allowance for credit losses for accounts receivable for the six months ending June 30, 2020:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	June 30, 2020
Allowance for credit losses:
Beginning balance	$	8,294
Provision for credit loss expense	9,762
Receivables charged-off	(7,157)
Total ending allowance balance	$	10,899

Tacoma LNG Facility

In August 2015, PSE filed a proposal with the Washington Utilities and Transportation Commission (Washington Commission) to develop an 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 greenhouse gas (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.

If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the 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, $224.5 million and $199.9 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 June 30, 2020, and December 31, 2019, respectively. Additionally, $0.7 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for each of the six months ended June 30, 2020, and June 30, 2019, respectively. Additionally, $185.1 million and $162.8 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 June 30, 2020, and December 31, 2019, respectively, as PSE is a regulated entity.

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New Accounting Pronouncements

6 Months Ended

Jun. 30, 2020

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Credit Losses

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables. It also applies to off-balance sheet credit exposures not accounted for as insurance and net investments in leases recognized by a lessor in accordance with Topic 842.

The Company adopted ASC 326 using the modified retrospective method for all financial assets measured at amortized cost. Results for reporting periods beginning after January 1, 2020, are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact was immaterial and the Company did not record a transition adjustment to retained earnings.

Fair Value Measurement

In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement". The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 5, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it has no material impact on the Company's results of operations, cash flows, or consolidated balance sheets.

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 June 30, 2020, 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.

Accounting Standards Issued but Not Yet Adopted

Retirement Benefits

In August 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures.

The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Accordingly, the Company will implement this update as of December 31, 2020 on a retrospective basis to all periods presented. The Company is in the process of evaluating potential impacts of these amendments to the required annual retirement benefits disclosures.

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Revenue

6 Months Ended

Jun. 30, 2020

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 June 30,				Six Months Ended June 30,
Revenue from contracts with customers:	2020		2019		2020		2019
Electric retail	$	433,112	$	463,219	$	1,040,805	$	1,100,408
Natural gas retail	168,117		145,222		533,753		467,782
Other	34,495		36,546		77,378		172,595
Total revenue from contracts with customers	635,724		644,987		1,651,936		1,740,785
Alternative revenue programs	19,750		4,351		20,900		(20,880)
Other non-customer revenue	(3,795)		21,592		24,973		65,864
Total operating revenue	$	651,679	$	670,930	$	1,697,809	$	1,785,769

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.

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Accounting for Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2020

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
	June 30, 2020					December 31, 2019
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	20,289	$	54,238	*	$	19,933	$	17,504
Natural gas derivatives (MMBtus)3	280.7 million	14,254		9,703		315.5 million	11,375		8,617
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121
Current		$	27,419	$	29,769		$	23,626	$	13,428
Long-term		7,124		34,172			7,682		12,693
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121

_______________

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 234.0 million One Million British Thermal Units (MMBtu) and purchased electricity of

7.1 million Megawatt Hours (MWhs) at June 30, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.

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 June 30, 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	$	34,543	$	—	$	34,543	$	(24,528)	$	—	$	10,015
Liabilities:
Energy derivative contracts	$	63,941	$	—	$	63,941	$	(24,528)	$	—	$	39,413

Puget Energy and Puget Sound Energy	At December 31, 2019
	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	$	31,308	$	—	$	31,308	$	(14,922)	$	—	$	16,386
Liabilities:
Energy derivative contracts	$	26,121	$	—	$	26,121	$	(14,922)	$	2,000	$	13,199

_______________

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 June 30,				Six Months Ended June 30,
(Dollars in Thousands)	Classification	2020		2019		2020		2019
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	4,764	$	(17,189)	$	(4,990)	$	(2,228)
Realized	Electric generation fuel	(743)		(1,333)		553		11,995
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	7,398		(13,143)		(31,388)		(12,917)
Realized	Purchased electricity	(6,228)		4,961		(12,163)		41,253
Total gain (loss) recognized in income on derivatives		$	5,191	$	(26,704)	$	(47,988)	$	38,103

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 June 30, 2020, approximately 98.0% 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 2.1% 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 June 30, 2020, PSE had cash posted as collateral of $9.0 million related to contracts executed on the ICE platform. Also, as of June 30, 2020, PSE had $6.3 million in a 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 six months ended June 30, 2020.

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 June 30, 2020						At December 31, 2019
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	28,552	$	—	$	28,552	$	6,110	$	—	$	6,110
Requested credit for adequate assurance	6,331		—		—		5,253		—		—
Forward value of contract3	5,327		—		N/A		—		14,827		N/A
Total	$	40,210	$	—	$	28,552	$	11,363	$	14,827	$	6,110

_______________

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

6 Months Ended

Jun. 30, 2020

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 totaling $52.5 million at June 30, 2020, and $51.5 million at December 31, 2019, 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		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,162,530	$	7,608,405	$	5,512,225	$	7,004,316
Long-term debt (variable-rate)	2	234,000		234,000		408,100		408,100
Total liabilities		$	6,396,530	$	7,842,405	$	5,920,325	$	7,412,416

Puget Sound Energy		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818
Total liabilities		$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818

_______________

¹ The carrying value includes debt issuances costs of $23.1 million and $24.1 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

² The carrying value includes debt issuances costs of $23.6 million and $24.4 million for June 30, 2020, and December 31, 2019, 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 June 30, 2020						Fair Value At December 31, 2019
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	19,763	$	526	$	20,289	$	19,282	$	651	$	19,933
Natural gas derivative instruments	13,634		620		14,254		9,852		1,523		11,375
Total assets	$	33,397	$	1,146	$	34,543	$	29,134	$	2,174	$	31,308
Liabilities:
Electric derivative instruments	$	25,103	$	29,135	$	54,238	$	13,474	$	4,030	$	17,504
Natural gas derivative instruments	9,425		278		9,703		8,376		241		8,617
Total liabilities	$	34,528	$	29,413	$	63,941	$	21,850	$	4,271	$	26,121

The following tables present 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 June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(26,305)	$	1,092	$	(25,213)	$	5,012	$	2,758	$	7,770
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	(2,284)		—		(2,284)		(6,190)		—		(6,190)
Included in regulatory assets / liabilities	—		(39)		(39)		—		382		382
Settlements	(20)		(711)		(731)		574		(1,619)		(1,045)
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		(1,842)		877		(965)
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(3,378)	$	1,282	$	(2,096)	$	1,362	$	1,673	$	3,035
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2	(26,837)		—		(26,837)		6,135		—		6,135
Included in regulatory assets / liabilities	—		284		284		—		2,279		2,279
Settlements	1,606		(1,224)		382		(12,909)		(2,718)		(15,627)
Transferred into Level 3	—		—		—		4,391		(398)		3,993
Transferred out of Level 3	—		—		—		(1,425)		1,562		137
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

_______________

^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 $(23.1) million and $(4.7) million for three months ended June 30, 2020 and 2019, respectively.

^2. 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 $(25.4) million and $(2.4) million for six months ended June 30, 2020 and 2019, 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 June 30, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	526	$	29,135	Discounted cash flow	Power prices (per MWh)	$	22.97	$	40.05	$	30.14
Natural gas	$	620	$	278	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.10	$	3.08	$	1.78

_______________

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, 2019:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	651	$	4,030	Discounted cash flow	Power prices (per MWh)	$	9.00	$	43.85	$	33.99
Natural gas	$	1,523	$	241	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.25	$	3.18	$	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 June 30, 2020, and December 31, 2019, a hypothetical 10.0% 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 $5.6 million and $2.5 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.

At March 31, 2020, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. 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". Differences between the fair market value and the carrying value of assets held at PSE were recorded at PE. The Rocky Reach contract was determined to be impaired due to a decrease in forward prices for this contract of 7.6% from December 31, 2019, causing an impairment of $52.6 million. While this impairment of the intangible asset held at Puget Energy is the result of a decline in forward prices and the corresponding valuation impact, the underlying power purchase contract is included within rates at PSE.

The following table presents the impairment recorded to the Company's intangible asset contracts, 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	$	21.27
	Power contract costs per quarter (in thousands)	$	6,308	$	7,085	$	6,468
December 31, 2019	Power prices (per MWh)	$	11.75	$	31.44	$	22.53
	Power contract costs per quarter (in thousands)	$	6,237	$	7,087	$	6,421

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Retirement Benefits

3 Months Ended

Jun. 30, 2020

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. 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. Non-represented employees and 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 (Other Benefits) 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 and six months ended June 30, 2020 and 2019:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,449)		(12,624)		—		—		(98)		(98)
Amortization of prior service cost	(292)		(495)		87		83		—		—
Amortization of net loss (gain)	2,099		251		512		341		(19)		(63)
Net periodic benefit cost	$	1,822	$	(365)	$	1,137	$	1,258	$	22	$	(33)

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,951)		(25,248)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(990)		174		166		—		—
Amortization of net loss (gain)	4,080		501		1,098		683		(41)		(125)
Net periodic benefit cost	$	3,101	$	(730)	$	2,416	$	2,518	$	43	$	(63)

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,451)		(12,628)		—		—		(98)		(98)
Amortization of prior service cost	(393)		(393)		87		83		—		—
Amortization of net loss (gain)	4,866		3,165		575		433		(33)		(109)
Net periodic benefit cost	$	4,486	$	2,647	$	1,200	$	1,350	$	8	$	(79)

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,955)		(25,257)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(787)		174		167		—		—
Amortization of net loss (gain)	9,522		6,330		1,234		866		(69)		(219)
Net periodic benefit cost	$	8,539	$	5,293	$	2,552	$	2,702	$	15	$	(157)

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2020 and December 31, 2019:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended		Year Ended		Six Months Ended		Year Ended		Six Months Ended		Year Ended
(Dollars in Thousands)	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Change in benefit obligation:
Benefit obligation at beginning of period	$	774,305	$	677,643	$	63,000	$	55,708	$	11,627	$	10,636
Amendments	—		—		—		—		—		9,049
Service cost	12,169		22,656		404		1,023		95		61
Interest cost	12,590		28,913		740		2,314		184		410
Curtailment Loss / (Gain)	—		—		—		—		—		(7,486)
Actuarial loss (gain)	1,134		84,272		(478)		6,756		34		(287)
Benefits paid	(23,990)		(36,740)		(17,643)		(2,801)		(494)		(982)
Medicare part D subsidy received	—		—		—		—		187		226
Administrative Expense	—		(2,439)		—		—		—		—
Benefit obligation at end of period	$	776,208	$	774,305	$	46,023	$	63,000	$	11,633	$	11,627

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, 2020, are expected to be at least $18.0 million, $26.1 million and $0.3 million, respectively. During the six months ended June 30, 2020, the Company contributed $17.6 million to fund the SERP. During the six months ended June 30, 2019, the Company contributed $1.0 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans.

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Regulated Operations

6 Months Ended

Jun. 30, 2020

Regulation and Rates [Abstract]

Regulation and Rates Disclosure

Regulation and Rates

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 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 which 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 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 $31.0 million, or 1.5% and the natural gas increase to $7.7 million, or 1.0%. PSE continues to review the original Commission order including the ramifications of certain tax issues and the order for clarification and expects to file a Compliance Filing to amend electric and natural gas tariffs and, upon approval of this filing, rates will go into effect.

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 GRC that was filed June 20, 2019:

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.

As a result of the Washington Commission's final order in the ERF, the 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 from January 1, 2018, through February 28, 2019, was 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 will 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. 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 period July 2020 through July 2021. As noted above, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items including administration of the required pass back of excess deferred tax reversals. On July 31, 2020, PSE received an order granting PSE’s motion for clarification which adjusted certain items within the final order, including treatment of protected excess deferred taxes. PSE is currently reviewing the order granting the motion for clarification.

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 also be changed in a power cost only rate case (PCORC). 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 June 30, 2020, 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 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 $2.1 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore an adjustment was booked to 2020 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2020 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 six months ended June 30, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $48.8 million of which $19.5 million was apportioned to customers and $1.1 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $46.4 million for the six months ended June 30, 2019, of which $17.3 million was apportioned to customers and accrued $0.2 million interest on the total deferred customer balance. The under recovery in 2020 led to an increase in the PCA deferral, and was a higher under recovery compared to the same period in 2019. The under recovery was due to power costs that were higher than what was collected in the allowed baseline for the six months ended June 30, 2020. Power costs have increased due to a number of factors such as the addition of new resources, increased rates on purchase power agreements and higher transmission costs. Also contributing to the under recovery in 2020 was a reduced load, used to calculate the baseline amount, which was due to warmer than normal weather in the first half of 2020 and to the effects of COVID-19 on energy usage and the economy. Contributing to the under recovery in 2019 were high power prices in the first quarter of 2019 due to cold weather in February and early March of 2019, which drove regional loads and demand for power up resulting in higher prices, and Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices.

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 remains which PSE will request to be amortized in its upcoming 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 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 Enbridge pipeline rupture, 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 was approved to collect $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. Finally, as part of the GRC final order, collection of the $114.4 million commodity deferrals and related interest was further lengthened to be collected over three years instead of two.

The following table presents the PGA mechanism balances and activity for six months ended June 30, 2020 and 2019:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30,		At December 31
PGA receivable balance and activity	2020		2019
PGA receivable beginning balance	$	132,766	$	9,922
Actual natural gas costs	169,697		406,162
Allowed PGA recovery	(217,916)		(289,876)
Interest	2,385		6,558
PGA receivable ending balance	$	86,932	$	132,766

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. As of June 30, 2020, and December 31, 2019, PSE had deferred GTZ depreciation expense balances of $41.1 million and $21.7 million, respectively. In addition to the depreciation expense deferral, PSE 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. As of June 30, 2020, and December 31, 2019, PSE has a deferred carrying charge balance of $2.0 million and $0.5 million, respectively. 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 general rate case 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 its next GRC. Finally, the final order changed the rate at which PSE could defer and recovery 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. 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 will automatically end when all of the funds are disbursed or September 30, 2020 whichever is soonest. 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.

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that 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 six months ended June 30, 2020, PSE incurred $9.9 million in storm-related electric transmission and distribution system restoration costs, of which no amount was deferred as a regulatory asset. This compares to $39.2 million incurred in storm-related electric transmission and distribution system restoration costs for the six months ended June 30, 2019, of which the Company deferred $0.4 million and $28.3 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. 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

6 Months Ended

Jun. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under the agreement with NorthWestern Energy, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has 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. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. Both the Washington Commission and the Montana Public Service Commission have placed the respective procedural calendars on hold until the terms of the deal can be updated for the additional Colstrip owner’s contractual purchase right and supplemental testimony can be filed. The original purchase agreement is written such that the purchase must close by December 31, 2020. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2019, and June 30, 2020, and determined that these criteria were not met. As such, 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, 2019.

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, 2019, during the six months ended June 30, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $935.3 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, 2019.

COVID-19

The outbreak of the novel coronavirus (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 June 30, 2020, the Company delivered lower electric and natural gas loads, 7.0% and 11.0%, 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 reductions were partially offset by 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 2020, 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.

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Leases (Notes)

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Leases

LeasesPSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the Tacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.

During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of

$14.7 million.

The components of lease cost were as follows:

Puget Energy and Puget Sound Energy	Three Months Ended June 30,				Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019
Finance lease cost:
Amortization of right-of-use asset	$	152	$	124	$	304	$	282
Interest on lease liabilities	9		10		19		19
Total finance lease cost	$	161	$	134	$	323	$	301
Operating lease cost1	$	5,669	$	5,223	$	11,149	$	10,007

_______________

¹ Includes $0.2 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended June 30, 2020 and 2019, respectively and $0.5 million for each of the six months ended June 30, 2020 and 2019, respectively.

Supplemental cash flow information related to leases was as follows:

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	$	7,726	$	9,131
Investing cash flow for operating leases1	3,423		876
Operating cash flow for finance leases	19		19
Financing cash flow for finance leases	304		282
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	4,996		1,840

_______________

¹ Includes $0.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the six months ended June 30, 2020 and 2019, respectively.

Supplemental balance sheet information related to leases was as follows:

Puget Sound Energy
(Dollars in Thousands)	June 30,			December 31,
Operating Leases	2020			2019
Operating lease right-of-use asset	$	179,658		$	183,048
Operating leases liabilities current	16,609			15,862
Operating lease liabilities long-term	170,250			174,327
Total Operating lease liabilities:	$	186,859		$	190,189
Finance Leases
Common Plant	$	1,185		$	1,488
Other current liabilities	616			669
Other deferred credits	519			811
Total finance lease liabilities	$	1,135		$	1,480
Weighted Average Remaining Lease Term
Operating leases	18.93 Years			19.24 Years
Finance leases	2.29 Years			2.76 Years
Weighted Average Discount Rate
Operating leases	3.59		%	3.59		%
Finance leases	2.98		%	2.98		%

The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2020, and December 31, 2019, respectively

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At June 30,	Operating Leases		Finance Leases
2020 (remaining six months)	$	11,653	$	320
2021	23,222		508
2022	22,578		279
2023	22,140		98
2024	21,415		—
Thereafter	162,810		—
Total lease payments	$	263,818	$	1,205
Less imputed interest	(76,959)		(70)
Total	$	186,859	$	1,135

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480

Leases

LeasesPSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the Tacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.

During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of

$14.7 million.

The components of lease cost were as follows:

Puget Energy and Puget Sound Energy	Three Months Ended June 30,				Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019
Finance lease cost:
Amortization of right-of-use asset	$	152	$	124	$	304	$	282
Interest on lease liabilities	9		10		19		19
Total finance lease cost	$	161	$	134	$	323	$	301
Operating lease cost1	$	5,669	$	5,223	$	11,149	$	10,007

_______________

¹ Includes $0.2 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended June 30, 2020 and 2019, respectively and $0.5 million for each of the six months ended June 30, 2020 and 2019, respectively.

Supplemental cash flow information related to leases was as follows:

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	$	7,726	$	9,131
Investing cash flow for operating leases1	3,423		876
Operating cash flow for finance leases	19		19
Financing cash flow for finance leases	304		282
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	4,996		1,840

_______________

¹ Includes $0.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the six months ended June 30, 2020 and 2019, respectively.

Supplemental balance sheet information related to leases was as follows:

Puget Sound Energy
(Dollars in Thousands)	June 30,			December 31,
Operating Leases	2020			2019
Operating lease right-of-use asset	$	179,658		$	183,048
Operating leases liabilities current	16,609			15,862
Operating lease liabilities long-term	170,250			174,327
Total Operating lease liabilities:	$	186,859		$	190,189
Finance Leases
Common Plant	$	1,185		$	1,488
Other current liabilities	616			669
Other deferred credits	519			811
Total finance lease liabilities	$	1,135		$	1,480
Weighted Average Remaining Lease Term
Operating leases	18.93 Years			19.24 Years
Finance leases	2.29 Years			2.76 Years
Weighted Average Discount Rate
Operating leases	3.59		%	3.59		%
Finance leases	2.98		%	2.98		%

The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2020, and December 31, 2019, respectively

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At June 30,	Operating Leases		Finance Leases
2020 (remaining six months)	$	11,653	$	320
2021	23,222		508
2022	22,578		279
2023	22,140		98
2024	21,415		—
Thereafter	162,810		—
Total lease payments	$	263,818	$	1,205
Less imputed interest	(76,959)		(70)
Total	$	186,859	$	1,135

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480

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Other

6 Months Ended

Jun. 30, 2020

Other [Abstract]

Long-term Debt

Long-Term Debt

On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes (Notes) at an interest rate of 4.1%. The Notes pay interest semi-annually and are due to mature on June 15, 2030. The proceeds from the issuance of the Notes were used to pay $150.0 million under our term loan credit facility, pay $31.6 million of our revolving credit facility, and to redeem $450.0 million in principal amount of the 6.5% senior secured notes due December 15, 2020 and to pay related fees and expenses.

On June 18, 2020, Puget Energy redeemed the $450.0 million senior secured notes due December 15, 2020 and paid related fees and expenses for a total redemption price of $463.2 million. Excluding the repayment of the $450.0 million principal amount and $0.3 million of unamortized debt discount and issuance cost, the extinguishment incurred a $13.5 million loss, which includes $0.4 million of accrued interest expense and is reported in the Puget Energy "Interest Expense" line item as of June 30, 2020.

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, 2019.

Short-term Debt

Short-Term Debt

During the six months ended June 30, 2020, commercial paper markets were significantly impacted for a period of time due to COVID-19, during which time the Company drew short term funding from its credit facility. Commercial paper markets improved as of June 30, 2020, at which time no amount was drawn under PSE's credit facility and $140.0 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, 2019.

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Accounting Policies (Tables)

3 Months Ended

Jun. 30, 2020

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 six months ending June 30, 2020:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	June 30, 2020
Allowance for credit losses:
Beginning balance	$	8,294
Provision for credit loss expense	9,762
Receivables charged-off	(7,157)
Total ending allowance balance	$	10,899

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Revenue (Tables)

6 Months Ended

Jun. 30, 2020

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 June 30,				Six Months Ended June 30,
Revenue from contracts with customers:	2020		2019		2020		2019
Electric retail	$	433,112	$	463,219	$	1,040,805	$	1,100,408
Natural gas retail	168,117		145,222		533,753		467,782
Other	34,495		36,546		77,378		172,595
Total revenue from contracts with customers	635,724		644,987		1,651,936		1,740,785
Alternative revenue programs	19,750		4,351		20,900		(20,880)
Other non-customer revenue	(3,795)		21,592		24,973		65,864
Total operating revenue	$	651,679	$	670,930	$	1,697,809	$	1,785,769

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Accounting for Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2020

Derivative [Line Items]

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 June 30, 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	$	34,543	$	—	$	34,543	$	(24,528)	$	—	$	10,015
Liabilities:
Energy derivative contracts	$	63,941	$	—	$	63,941	$	(24,528)	$	—	$	39,413

Puget Energy and Puget Sound Energy	At December 31, 2019
	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	$	31,308	$	—	$	31,308	$	(14,922)	$	—	$	16,386
Liabilities:
Energy derivative contracts	$	26,121	$	—	$	26,121	$	(14,922)	$	2,000	$	13,199

_______________

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 June 30,				Six Months Ended June 30,
(Dollars in Thousands)	Classification	2020		2019		2020		2019
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	4,764	$	(17,189)	$	(4,990)	$	(2,228)
Realized	Electric generation fuel	(743)		(1,333)		553		11,995
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	7,398		(13,143)		(31,388)		(12,917)
Realized	Purchased electricity	(6,228)		4,961		(12,163)		41,253
Total gain (loss) recognized in income on derivatives		$	5,191	$	(26,704)	$	(47,988)	$	38,103

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 June 30, 2020						At December 31, 2019
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	28,552	$	—	$	28,552	$	6,110	$	—	$	6,110
Requested credit for adequate assurance	6,331		—		—		5,253		—		—
Forward value of contract3	5,327		—		N/A		—		14,827		N/A
Total	$	40,210	$	—	$	28,552	$	11,363	$	14,827	$	6,110

_______________

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.

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
	June 30, 2020					December 31, 2019
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	20,289	$	54,238	*	$	19,933	$	17,504
Natural gas derivatives (MMBtus)3	280.7 million	14,254		9,703		315.5 million	11,375		8,617
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121
Current		$	27,419	$	29,769		$	23,626	$	13,428
Long-term		7,124		34,172			7,682		12,693
Total derivative contracts		$	34,543	$	63,941		$	31,308	$	26,121

_______________

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 234.0 million One Million British Thermal Units (MMBtu) and purchased electricity of

7.1 million Megawatt Hours (MWhs) at June 30, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.

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Fair Value Measurements (Tables)

3 Months Ended

6 Months Ended

Jun. 30, 2020

Jun. 30, 2020

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		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	$	6,162,530	$	7,608,405	$	5,512,225	$	7,004,316
Long-term debt (variable-rate)	2	234,000		234,000		408,100		408,100
Total liabilities		$	6,396,530	$	7,842,405	$	5,920,325	$	7,412,416

Puget Sound Energy		At June 30, 2020				At December 31, 2019
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818
Total liabilities		$	4,337,090	$	5,992,573	$	4,336,142	$	5,571,818

_______________

¹ The carrying value includes debt issuances costs of $23.1 million and $24.1 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

² The carrying value includes debt issuances costs of $23.6 million and $24.4 million for June 30, 2020, and December 31, 2019, 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 June 30, 2020						Fair Value At December 31, 2019
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	19,763	$	526	$	20,289	$	19,282	$	651	$	19,933
Natural gas derivative instruments	13,634		620		14,254		9,852		1,523		11,375
Total assets	$	33,397	$	1,146	$	34,543	$	29,134	$	2,174	$	31,308
Liabilities:
Electric derivative instruments	$	25,103	$	29,135	$	54,238	$	13,474	$	4,030	$	17,504
Natural gas derivative instruments	9,425		278		9,703		8,376		241		8,617
Total liabilities	$	34,528	$	29,413	$	63,941	$	21,850	$	4,271	$	26,121

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

The following tables present 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 June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(26,305)	$	1,092	$	(25,213)	$	5,012	$	2,758	$	7,770
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	(2,284)		—		(2,284)		(6,190)		—		(6,190)
Included in regulatory assets / liabilities	—		(39)		(39)		—		382		382
Settlements	(20)		(711)		(731)		574		(1,619)		(1,045)
Transferred into Level 3	—		—		—		—		—		—
Transferred out of Level 3	—		—		—		(1,842)		877		(965)
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020						2019
Level 3 Roll-Forward Net Asset/(Liability)	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	(3,378)	$	1,282	$	(2,096)	$	1,362	$	1,673	$	3,035
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2	(26,837)		—		(26,837)		6,135		—		6,135
Included in regulatory assets / liabilities	—		284		284		—		2,279		2,279
Settlements	1,606		(1,224)		382		(12,909)		(2,718)		(15,627)
Transferred into Level 3	—		—		—		4,391		(398)		3,993
Transferred out of Level 3	—		—		—		(1,425)		1,562		137
Balance at end of period	$	(28,609)	$	342	$	(28,267)	$	(2,446)	$	2,398	$	(48)

_______________

^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 $(23.1) million and $(4.7) million for three months ended June 30, 2020 and 2019, respectively.

^2. 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 $(25.4) million and $(2.4) million for six months ended June 30, 2020 and 2019, 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 June 30, 2020:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	526	$	29,135	Discounted cash flow	Power prices (per MWh)	$	22.97	$	40.05	$	30.14
Natural gas	$	620	$	278	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.10	$	3.08	$	1.78

_______________

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, 2019:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	651	$	4,030	Discounted cash flow	Power prices (per MWh)	$	9.00	$	43.85	$	33.99
Natural gas	$	1,523	$	241	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.25	$	3.18	$	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	$	21.27
	Power contract costs per quarter (in thousands)	$	6,308	$	7,085	$	6,468
December 31, 2019	Power prices (per MWh)	$	11.75	$	31.44	$	22.53
	Power contract costs per quarter (in thousands)	$	6,237	$	7,087	$	6,421

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2020

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs

The following tables summarize the Company’s net periodic benefit cost for the three and six months ended June 30, 2020 and 2019:

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,449)		(12,624)		—		—		(98)		(98)
Amortization of prior service cost	(292)		(495)		87		83		—		—
Amortization of net loss (gain)	2,099		251		512		341		(19)		(63)
Net periodic benefit cost	$	1,822	$	(365)	$	1,137	$	1,258	$	22	$	(33)

Puget Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,951)		(25,248)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(990)		174		166		—		—
Amortization of net loss (gain)	4,080		501		1,098		683		(41)		(125)
Net periodic benefit cost	$	3,101	$	(730)	$	2,416	$	2,518	$	43	$	(63)

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	6,172	$	5,287	$	176	$	256	$	46	$	16
Interest cost	6,292		7,216		362		578		93		112
Expected return on plan assets	(12,451)		(12,628)		—		—		(98)		(98)
Amortization of prior service cost	(393)		(393)		87		83		—		—
Amortization of net loss (gain)	4,866		3,165		575		433		(33)		(109)
Net periodic benefit cost	$	4,486	$	2,647	$	1,200	$	1,350	$	8	$	(79)

Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019		2020		2019
Components of net periodic benefit cost:
Service cost	$	12,169	$	10,574	$	404	$	512	$	95	$	33
Interest cost	12,590		14,433		740		1,157		184		224
Expected return on plan assets	(24,955)		(25,257)		—		—		(195)		(195)
Amortization of prior service cost	(787)		(787)		174		167		—		—
Amortization of net loss (gain)	9,522		6,330		1,234		866		(69)		(219)
Net periodic benefit cost	$	8,539	$	5,293	$	2,552	$	2,702	$	15	$	(157)

Schedule of Changes in Projected Benefit Obligations

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2020 and December 31, 2019:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits				SERP Pension Benefits				Other Benefits
	Six Months Ended		Year Ended		Six Months Ended		Year Ended		Six Months Ended		Year Ended
(Dollars in Thousands)	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Change in benefit obligation:
Benefit obligation at beginning of period	$	774,305	$	677,643	$	63,000	$	55,708	$	11,627	$	10,636
Amendments	—		—		—		—		—		9,049
Service cost	12,169		22,656		404		1,023		95		61
Interest cost	12,590		28,913		740		2,314		184		410
Curtailment Loss / (Gain)	—		—		—		—		—		(7,486)
Actuarial loss (gain)	1,134		84,272		(478)		6,756		34		(287)
Benefits paid	(23,990)		(36,740)		(17,643)		(2,801)		(494)		(982)
Medicare part D subsidy received	—		—		—		—		187		226
Administrative Expense	—		(2,439)		—		—		—		—
Benefit obligation at end of period	$	776,208	$	774,305	$	46,023	$	63,000	$	11,633	$	11,627

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Regulated Operations (Tables)

6 Months Ended

Jun. 30, 2020

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

Subsidiaries [Member] | Natural Gas [Member] | Purchased Gas Adjustment [Member]

Regulation and Rates [Line Items]

Schedule of PGA Receivable Payable

The following table presents the PGA mechanism balances and activity for six months ended June 30, 2020 and 2019:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30,		At December 31
PGA receivable balance and activity	2020		2019
PGA receivable beginning balance	$	132,766	$	9,922
Actual natural gas costs	169,697		406,162
Allowed PGA recovery	(217,916)		(289,876)
Interest	2,385		6,558
PGA receivable ending balance	$	86,932	$	132,766

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Leases (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2020

Dec. 31, 2019

Leases [Abstract]

Schedule of lease cost

The components of lease cost were as follows:

Puget Energy and Puget Sound Energy	Three Months Ended June 30,				Six Months Ended June 30,
(Dollars in Thousands)	2020		2019		2020		2019
Finance lease cost:
Amortization of right-of-use asset	$	152	$	124	$	304	$	282
Interest on lease liabilities	9		10		19		19
Total finance lease cost	$	161	$	134	$	323	$	301
Operating lease cost1	$	5,669	$	5,223	$	11,149	$	10,007

_______________

¹ Includes $0.2 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended June 30, 2020 and 2019, respectively and $0.5 million for each of the six months ended June 30, 2020 and 2019, respectively.

Schedule of lease assets and liabilities

Supplemental balance sheet information related to leases was as follows:

Puget Sound Energy
(Dollars in Thousands)	June 30,			December 31,
Operating Leases	2020			2019
Operating lease right-of-use asset	$	179,658		$	183,048
Operating leases liabilities current	16,609			15,862
Operating lease liabilities long-term	170,250			174,327
Total Operating lease liabilities:	$	186,859		$	190,189
Finance Leases
Common Plant	$	1,185		$	1,488
Other current liabilities	616			669
Other deferred credits	519			811
Total finance lease liabilities	$	1,135		$	1,480
Weighted Average Remaining Lease Term
Operating leases	18.93 Years			19.24 Years
Finance leases	2.29 Years			2.76 Years
Weighted Average Discount Rate
Operating leases	3.59		%	3.59		%
Finance leases	2.98		%	2.98		%

Schedule of maturity of operating lease liability

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480

Schedule of maturity of finance lease liability

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480

Leases, Cash Flow

Supplemental cash flow information related to leases was as follows:

Puget Energy and Puget Sound Energy	Six Months Ended June 30,
(Dollars in Thousands)	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	$	7,726	$	9,131
Investing cash flow for operating leases1	3,423		876
Operating cash flow for finance leases	19		19
Financing cash flow for finance leases	304		282
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	4,996		1,840

_______________

¹ Includes $0.5 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the six months ended June 30, 2020 and 2019, respectively.

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Summary of Consolidation and Significant Accounting Policy (Details) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2020 USD ($) mi²	Jun. 30, 2020 USD ($) mi²	Dec. 31, 2019 USD ($)	Jun. 30, 2019 USD ($)
Summary of Consolidation Policy
Allowance for Credit Losses, Beginning Balance			$ 8,294
Provision for Credit Loss		$ 9,762
Receivables Charged-Off	$ (7,157)
Allowance for Credit Loss, Ending Balance	$ 10,899	$ 10,899
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000	6,000
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%	43.00%
Construction in Progress, Gross	$ 185,100	$ 185,100		$ 162,800
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%	57.00%
Construction in Progress, Gross	$ 224,500	$ 224,500		$ 199,900
Puget LNG [Member] | Non-Utility Expense And Other [Member]
Summary of Consolidation Policy
Operating Costs and Expenses		$ 700

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	$ 5,704	$ 6,731	$ 11,713	$ 17,974
Revenues	651,679	670,930	1,697,809	1,785,769
Revenue from Contract with Customer, Including Assessed Tax	635,724	644,987	1,651,936	1,740,785
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	433,112	463,219	1,040,805	1,100,408
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	168,117	145,222	533,753	467,782
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	34,495	36,546	77,378	172,595
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	19,750	4,351	20,900	(20,880)
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	(3,795)	21,592	24,973	65,864
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	5,704	6,731	11,713	17,974
Revenues	$ 651,679	$ 670,930	$ 1,697,809	$ 1,785,769

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Accounting for Derivative Instruments and Hedging Activities Narrative (Details) MMBTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2020 USD ($) MMBTU	Dec. 31, 2019 MMBTU
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years
Electric Generation Fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	234.0	229.3
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	98.00%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	2.10%
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$ 9.0
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 6.3

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Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions	Jun. 30, 2020 USD ($) MMBTU	Dec. 31, 2019 USD ($) MMBTU
Derivative [Line Items]
Current, Assets	$ 27,419	$ 23,626
Long-term, Assets	7,124	7,682
Current, Liabilities	29,769	13,428
Long-term, Liabilities	34,172	12,693
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current, Assets	27,419	23,626
Long-term, Assets	7,124	7,682
Assets	34,543	31,308
Current, Liabilities	29,769	13,428
Long-term, Liabilities	34,172	12,693
Derivative Liability	$ 63,941	$ 26,121
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	280.7	315.5
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	$ 20,289	$ 19,933
Derivative Liability	54,238	17,504
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	14,254	11,375
Derivative Liability	$ 9,703	$ 8,617
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	234.0	229.3
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	7.1	10.4
Designated as Hedging Instrument
Derivative [Line Items]
Derivative Liability		$ 26,121

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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	Jun. 30, 2020	Dec. 31, 2019
Assets:
Gross Amount Recognized in the Statement of Financial Position	$ 34,543	$ 31,308
Gross Amounts Offset in the Statement of Financial Position	0	0
Assets	34,543	31,308
Commodity Contracts	(24,528)	(14,922)
Cash Collateral Received	0	0
Net Amount	10,015	16,386
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	63,941	26,121
Gross Amounts Offset in the Statement of Financial Position	0	0
Derivative Liability	63,941	26,121
Commodity Contracts	(24,528)	(14,922)
Cash Collateral Posted	0	2,000
Net Amount	$ 39,413	$ 13,199

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Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 12,162	$ (30,332)	$ (36,379)	$ (15,145)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	5,191	(26,704)	(47,988)	38,103
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	4,764	(17,189)	(4,990)	(2,228)
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	(743)	(1,333)	553	11,995
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(6,228)	4,961	(12,163)	41,253
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	$ 7,398	$ (13,143)	$ (31,388)	$ (12,917)

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Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ 40,210	$ 11,363
Posted Collateral	0	14,827
Additional Collateral, Aggregate Fair Value	28,552	6,110
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	9,000
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	28,552	6,110
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	28,552	6,110
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	6,331	5,253
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	5,327	0
Posted Collateral	$ 0	$ 14,827

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Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Liabilities:
Total long-term debt	$ 6,396,530	$ 5,920,325
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure	52,500	51,500
Subsidiaries [Member]
Liabilities:
Total long-term debt	4,337,090	4,336,142
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt	6,396,530	5,920,325
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	6,162,530	5,512,225	[1]
Long-term debt (variable-rate)	234,000	408,100
Debt issuance costs	23,100	24,100
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Total long-term debt	7,842,405	7,412,416
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	7,608,405	7,004,316	[1]
Long-term debt (variable-rate)	234,000	408,100
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt	4,337,090	4,336,142
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	4,337,090	4,336,142	[2]
Debt issuance costs	23,600	24,400
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt	5,992,573	5,571,818
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	$ 5,992,573	$ 5,571,818	[2]

[1] ¹ The carrying value includes debt issuances costs of $23.1 million and $24.1 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

[2] ² The carrying value includes debt issuances costs of $23.6 million and $24.4 million for June 30, 2020, and December 31, 2019, respectively, which are not included in fair value.

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Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended					6 Months Ended
	Jun. 30, 2020		Mar. 31, 2020	Jun. 30, 2019		Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ (25,213)		$ (2,096)			$ (2,096)
Balance at beginning of period				$ 7,770			$ 3,035
Included in earnings	(2,284)	[1]		(6,190)	[1]	(26,837)	6,135
Included in regulatory assets/liabilities	(39)			382		284	2,279
Settlements	(731)			(1,045)			(15,627)
Settlements						382
Transferred into Level 3							3,993
Transferred into Level 3	0			0		0
Transferred out of Level 3	0			(965)		0
Transferred out of Level 3							137
Balance at end of period	(28,267)		$ (25,213)	(48)		(28,267)	(48)
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	(5,600)					(5,600)		$ (2,500)
Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Change in forward prices			7.60%
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	(26,305)		$ (3,378)			(3,378)
Balance at beginning of period				5,012			1,362
Included in earnings	(2,284)			(6,190)		(26,837)	6,135
Included in regulatory assets/liabilities	0			0		0	0
Settlements	(20)						(12,909)
Settlements				574		1,606
Transferred into Level 3							4,391
Transferred into Level 3	0			0		0
Transferred out of Level 3	0			(1,842)		0	(1,425)
Balance at end of period	(28,609)		(26,305)	(2,446)		(28,609)	(2,446)
Gain (loss) on derivatives	(23,100)			(4,700)		(25,400)	(2,400)
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	1,092		1,282	2,758		1,282	1,673
Included in earnings	0			0		0	0
Included in regulatory assets/liabilities	(39)			382		284	2,279
Settlements	(711)			(1,619)		(1,224)	(2,718)
Transferred into Level 3	0			0		0	(398)
Transferred out of Level 3	0					0
Transferred out of Level 3				877			1,562
Balance at end of period	342		$ 1,092	$ 2,398		342	$ 2,398
Level 2 [Member] | Carrying Value [Member] | Discounted cash flow [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt issuance costs	23,100					23,100		24,100
Level 2 [Member] | Carrying Value [Member] | Discounted cash flow [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt issuance costs	23,600					23,600		24,400
Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	34,543					34,543		31,308
Derivative Liability	63,941					63,941		26,121
Fair Value, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	20,289					20,289		19,933
Derivative Liability	54,238					54,238		17,504
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	14,254					14,254		11,375
Derivative Liability	9,703					9,703		8,617
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	33,397					33,397		29,134
Derivative Liability	34,528					34,528		21,850
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	19,763					19,763		19,282
Derivative Liability	25,103					25,103		13,474
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	13,634					13,634		9,852
Derivative Liability	9,425					9,425		8,376
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	1,146					1,146		2,174
Derivative Liability	29,413					29,413		4,271
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	526					526		651	[2]
Derivative Liability	29,135					29,135		4,030	[2]
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	620					620		1,523	[2]
Derivative Liability	$ 278					$ 278		$ 241	[2]

[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 $(23.1) million and $(4.7) million for three months ended June 30, 2020 and 2019, respectively. ^2. 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 $(25.4) million and $(2.4) million for six months ended June 30, 2020 and 2019, respectively.

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

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Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended					6 Months Ended		12 Months Ended
	Jun. 30, 2020 USD ($)		Mar. 31, 2020 USD ($) $ / MWh	Jun. 30, 2019 USD ($)		Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2019 USD ($) $ / MWh
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	10.00%					10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ (5,600,000)					$ (5,600,000)		$ (2,500,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability Value	(28,267,000)		$ (25,213,000)	$ (48,000)		(28,267,000)	$ (48,000)	$ (2,096,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	(2,284,000)	[1]		(6,190,000)	[1]	(26,837,000)	6,135,000
Included in regulatory assets/liabilities	(39,000)			382,000		284,000	2,279,000
Settlements	731,000			1,045,000			15,627,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			0		0
Transferred out of Level 3	0			965,000		0
Rocky Reach
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
Asset Impairment Charges			$ 52,600,000
Change in forward prices			7.60%
Rocky Reach | 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					11.75
Fair Value Inputs, Power Contract Costs			$ 6,308					$ 6,237
Discounted cash flow [Member] | High [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh			29.05					31.44
Fair Value Inputs, Power Contract Costs			$ 7,085					$ 7,087
Discounted cash flow [Member] | Weighted Average [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh			21.27					22.53
Fair Value Inputs, Power Contract Costs			$ 6,468					$ 6,421
Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	34,543,000					34,543,000		31,308,000
Derivative Liability	63,941,000					63,941,000		26,121,000
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	1,146,000					1,146,000		2,174,000
Derivative Liability	29,413,000					29,413,000		4,271,000
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability Value	(28,609,000)		$ (26,305,000)	(2,446,000)		(28,609,000)	(2,446,000)	$ (3,378,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	(2,284,000)			(6,190,000)		(26,837,000)	6,135,000
Included in regulatory assets/liabilities	0			0		0	0
Settlements	20,000						12,909,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			0		0
Transferred out of Level 3	0			1,842,000		$ 0	1,425,000
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						22.97		9.00
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						40.05		43.85
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)						30.14		33.99
Electric Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	20,289,000					$ 20,289,000		$ 19,933,000
Derivative Liability	54,238,000					54,238,000		17,504,000
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	526,000					526,000		651,000	[2]
Derivative Liability	29,135,000					29,135,000		$ 4,030,000	[2]
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	0			0		0	0
Included in regulatory assets/liabilities	(39,000)			382,000		284,000	2,279,000
Settlements	711,000			1,619,000		1,224,000	2,718,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			$ 0		0	$ (398,000)
Transferred out of Level 3	0					$ 0
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)						1.10		1.25
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)						3.08		3.18
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)						1.78		2.47
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	14,254,000					$ 14,254,000		$ 11,375,000
Derivative Liability	9,703,000					9,703,000		8,617,000
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	620,000					620,000		1,523,000	[2]
Derivative Liability	$ 278,000					$ 278,000		$ 241,000	[2]

[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 $(23.1) million and $(4.7) million for three months ended June 30, 2020 and 2019, respectively. ^2. 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 $(25.4) million and $(2.4) million for six months ended June 30, 2020 and 2019, respectively.

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

XML

Retirement Benefits - Benefit Obligations (Details) - Subsidiaries [Member]	6 Months Ended
	Jun. 30, 2020
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%

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Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 6,172	$ 5,287	$ 12,169	$ 10,574	$ 22,656
Interest cost	6,292	7,216	12,590	14,433	28,913
Expected return on plan assets	(12,449)	(12,624)	(24,951)	(25,248)
Amortization of prior service cost	(292)	(495)	(787)	(990)
Amortization of net loss (gain)	2,099	251	4,080	501
Net periodic benefit cost	1,822	(365)	3,101	(730)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	176	256	404	512	1,023
Interest cost	362	578	740	1,157	2,314
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	87	83	174	166
Amortization of net loss (gain)	512	341	1,098	683
Net periodic benefit cost	1,137	1,258	2,416	2,518
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	46	16	95	33	61
Interest cost	93	112	184	224	$ 410
Expected return on plan assets	(98)	(98)	(195)	(195)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(19)	(63)	(41)	(125)
Net periodic benefit cost	22	(33)	43	(63)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	6,172	5,287	12,169	10,574
Interest cost	6,292	7,216	12,590	14,433
Expected return on plan assets	(12,451)	(12,628)	(24,955)	(25,257)
Amortization of prior service cost	(393)	(393)	(787)	(787)
Amortization of net loss (gain)	4,866	3,165	9,522	6,330
Net periodic benefit cost	4,486	2,647	8,539	5,293
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	176	256	404	512
Interest cost	362	578	740	1,157
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	87	83	174	167
Amortization of net loss (gain)	575	433	1,234	866
Net periodic benefit cost	1,200	1,350	2,552	2,702
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	46	16	95	33
Interest cost	93	112	184	224
Expected return on plan assets	(98)	(98)	(195)	(195)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(33)	(109)	(69)	(219)
Net periodic benefit cost	$ 8	$ (79)	$ 15	$ (157)

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Retirement Benefits Change in Net Benefit Obligation (Details) - Parent Company [Member] - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			$ 774,305	$ 677,643	$ 677,643
Service cost	$ 6,172	$ 5,287	12,169	10,574	22,656
Interest cost	6,292	7,216	12,590	14,433	28,913
Actuarial loss (gain)			1,134		84,272
Benefits paid			(23,990)		(36,740)
Medicare part D subsidy received			0		0
Administrative Expense			0		(2,439)
Benefit obligation at end of period	776,208		776,208		774,305
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			63,000	55,708	55,708
Service cost	176	256	404	512	1,023
Interest cost	362	578	740	1,157	2,314
Actuarial loss (gain)			(478)		6,756
Benefits paid			(17,643)		(2,801)
Medicare part D subsidy received			0		0
Administrative Expense			0		0
Benefit obligation at end of period	46,023		46,023		63,000
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			11,627	10,636	10,636
Amendments			0		(9,049)
Service cost	46	16	95	33	61
Interest cost	93	$ 112	184	$ 224	410
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment			0		(7,486)
Actuarial loss (gain)			34		(287)
Benefits paid			(494)		(982)
Medicare part D subsidy received			187		226
Administrative Expense			0		0
Benefit obligation at end of period	$ 11,633		11,633		11,627
Qualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Amendments			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]
Amendments			$ 0		$ 0

XML

Retirement Benefits Activity (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2020
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 17.6	$ 1.0
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			26.1
Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

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Regulation and Rates (Details) - USD ($) $ in Thousands														3 Months Ended		6 Months Ended		12 Months Ended
	Jul. 31, 2020	Jul. 08, 2020	Apr. 06, 2020	Jan. 15, 2020	Nov. 01, 2019	Jun. 20, 2019	Apr. 10, 2019	Mar. 01, 2019	Nov. 07, 2018	May 01, 2018	Mar. 01, 2018	Dec. 19, 2017	Dec. 18, 2017	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019	Apr. 30, 2019	Jul. 21, 2020	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Regulation and Rates [Line Items]
Income tax (benefit) expense														$ (1,188)	$ 1,481	$ 2,796	$ 9,909
Depreciation & amortization														136,865	164,715	301,681	345,412
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities									7.49%
Income tax (benefit) expense										$ 34,600				1,999	2,327	15,264	21,157
Annual Power Cost Variability, Interest																1,100	200
PGA payable														86,932	132,766	86,932	132,766	$ 132,766			$ 9,922
Depreciation & amortization														136,816	$ 164,692	301,587	345,370
Liabilities, Other than Long-term Debt, Noncurrent			$ 11,000
Customer Bill Assistance			$ 1
Subsidiaries [Member] | Companys share [Member] | Under-collection [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount																48,800	46,400
Subsidiaries [Member] | Customer's share [Member] | Under-collection [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount																19,500	17,300
Subsidiaries [Member] | Subsequent Event [Member]
Regulation and Rates [Line Items]
Income tax (benefit) expense		$ 70,800
Liabilities, Other than Long-term Debt, Noncurrent																				$ 4,500
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Incurred During Period																9,900	39,200
Public Utilities, Rate Case, Deferred Storm Costs Threshold																						$ 10,000	$ 8,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs																						$ 500
General Rate Case [Member] | Subsidiaries [Member]
Regulation and Rates [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%
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage						6.90%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ (1,500)
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member] | Subsequent Event [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 31,000	$ 900
Public Utilities, Approved Rate Increase (Decrease), Percentage	1.50%	0.05%
Public Utilities, Interim Rate Increase (Decrease), Amount	$ 59,600	$ 29,500
Public Utilities, Interim Rate Increase (Decrease), Percentage	2.90%	1.60%
Public Utilities Attrition Adjustment Increase Decrease Amount		$ 23,900
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount	$ 30,100
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage						7.90%
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Subsequent Event [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 7,700	$ 1,300
Public Utilities, Approved Rate Increase (Decrease), Percentage	1.00%	0.15%
Public Utilities, Interim Rate Increase (Decrease), Amount	$ 42,900	$ 36,500
Public Utilities, Interim Rate Increase (Decrease), Percentage	5.60%	4.00%
Public Utilities Attrition Adjustment Increase Decrease Amount		$ 16,200
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount	$ 6,400
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Return on Equity, Percentage						9.80%
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member] | Subsequent Event [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Return on Equity, Percentage		9.40%
Public Utilities, Approved Equity Capital Structure, Percentage		48.50%
Public Utilities, Approved Debt Capital Structure, Percentage		7.39%
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage		6.80%
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage									0.90%
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 18,900
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage									2.70%
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 21,700		$ 6,100
Public Utilities, Approved Rate Increase (Decrease), Amount								$ 21,500			$ 25,900
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																			$ (72,900)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																			(3.40%)
Contract with Customer, Refund Liability														$ 100		100
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																			$ (23,600)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																			(2.70%)
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Deferred Revenue, Revenue Recognized																0
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Contract with Customer, Liability, Revenue Recognized																2,100
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage												3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage												5.00%	3.00%
General Rate Case, Electric [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				6.90%
General Rate Case, Natural Gas [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				7.90%
Purchased Gas Adjustment [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 17,800
Purchased natural gas costs																169,697		406,162
Purchased natural gas costs, recoverable																(217,916)		(289,876)
Purchased natural gas adjustment, interest																2,385		6,558
Annual revenue					100,600
Out of Cycle PGA					54,000
Under collected commodity balances					114,400
Commodity Costs					10,800
Refund to Customers, remaining balance					4,100
Refund to Customers					$ 54,700
Get to Zero Deferral Filing [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities							6.89%
Depreciation & amortization																41,100		21,700
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life							10 years
Carrying charges on deferral																2,000		$ 500
Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Deferred During Period																	400
Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Deferred During Period																$ 0	$ 28,300

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Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2020 USD ($)	Jun. 30, 2019 USD ($)
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Interest		$ 1.1	$ 0.2
Customer's share [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount		19.5	17.3
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		$ 48.8	$ 46.4
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

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Regulation and Rates (Details) - Subsidiaries [Member] - Purchased Gas Adjustment [Member] - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Regulation and Rates [Line Items]
Purchased natural gas costs	$ 169,697	$ 406,162
Purchased natural gas costs, recoverable	(217,916)	(289,876)
Purchased natural gas adjustment, interest	$ 2,385	$ 6,558

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Commitments and Contingencies (Details) $ in Millions	Jun. 30, 2020 USD ($)
Loss Contingencies [Line Items]
Purchase Obligation	$ 935.3
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%

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Leases (Details)	6 Months Ended
	Jun. 30, 2020
Leases [Abstract]
Remaining lease term (less than)	25 years
Lessee, lease, renewal term (up to)	50 years

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Leases - Schedule of the components of lease expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Related Party Transaction [Line Items]
Amortization of right-of-use asset	$ 152	$ 124	$ 304	$ 282
Interest on lease liabilities	9	10	19	19
Total finance lease cost	161	134	323	301
Operating lease cost	5,669	$ 5,223	11,149	$ 10,007
Subsidiaries
Related Party Transaction [Line Items]
Right-of-Use, Modification, Operating					$ 14,700
Land | Subsidiaries
Related Party Transaction [Line Items]
Operating lease cost	$ 200		$ 500

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Leases - Supplemental cash flow information related to leases (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Related Party Transaction [Line Items]
Operating cash flow for operating leases	$ 7,726	$ 9,131
Investing cash flow for operating leases	3,423	876
Operating cash flow for finance leases	19	19
Financing cash flow for finance leases	304	282
Subsidiaries
Related Party Transaction [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	4,996	1,840
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 4,996	$ 1,840

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Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Operating Leases
Operating lease right-of-use asset	$ 179,658	$ 183,048
Operating leases liabilities current	16,609	15,862
Operating lease liabilities long-term	170,250	174,327
Total Operating lease liabilities:	186,859	190,189
Finance Leases
Common Plant	1,185	1,488
Other current liabilities	616	669
Other deferred credits	519	811
Total finance lease liabilities	$ 1,135	$ 1,480
Weighted Average Remaining Lease Term
Operating leases	18 years 11 months 4 days	19 years 2 months 26 days
Finance leases	2 years 3 months 14 days	2 years 9 months 3 days
Weighted Average Discount Rate
Operating leases	3.59%	3.59%
Finance leases	2.98%	2.98%

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Leases - Schedule of future minimum lease payments (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Finance Leases
Lessee, Operating Lease, Liability, Payments, Due		$ 269,398
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	$ 76,959	79,209
Finance Lease, Liability, Undiscounted Excess Amount	70	48
Finance Lease, Liability, Payment, Due		1,528
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	11,653
Finance Lease, Liability, Payments, Remainder of Fiscal Year	320
Lessee, Operating Lease, Liability, Payments, Due Year Two	23,222	22,527
Finance Lease, Liability, Payments, Due Year Two	508	508
Lessee, Operating Lease, Liability, Payments, Due Year Five	21,415	20,690
Finance Lease, Liability, Payments, Due Year Five	0	0
Finance Lease, Liability, Payments, Due Next Twelve Months		643
Lessee, Operating Lease, Liability, Payments, Due Year Three	22,578	21,856
Lessee, Operating Lease, Liability, Payments, Due Year Four	22,140	21,415
Finance Lease, Liability, Payments, Due Year Three	279	279
Finance Lease, Liability, Payments, Due Year Four	98	98
Finance Lease, Liability, Payments, Due after Year Five	0	0
Lessee, Operating Lease, Liability, Payments, Due after Year Five	$ 162,810	160,410
Operating Leases, Future Minimum Payments Due, Next Twelve Months		$ 22,500

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Other (Details) - USD ($)		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2020	Jun. 30, 2019	Jun. 18, 2020	May 19, 2020
Short-term Debt [Line Items]
Repayments of Debt		$ 174,100,000	$ 0
Gain (Loss) on Extinguishment of Debt		(13,546,000)	$ 0
term-loan [Member]
Short-term Debt [Line Items]
Repayments of Debt		150,000,000.0
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Repayments of Debt		31,600,000
4.100% Senior Secured Note Due 2030 [Member] | Senior Secured Note [Member]
Short-term Debt [Line Items]
Long-term Debt, Gross					$ 650,000,000.0
Debt Instrument, Interest Rate, Stated Percentage					4.10%
6.500% Senior Secured Note Due 2020 [Member] | Senior Secured Note [Member]
Short-term Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.50%
Extinguishment of Debt, Amount		463,200,000
Long-term debt, Principal				$ 450,000,000.0
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				$ 300,000
Gain (Loss) on Extinguishment of Debt		13,500,000
Debt Instrument, Increase, Accrued Interest		400,000
Subsidiaries [Member]
Short-term Debt [Line Items]
Commercial Paper	$ 140,000,000.0	$ 140,000,000.0
Subsidiaries [Member] | Working Capital Needs [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 0