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 September 30, 20172022
OR
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
psd-20220930_g1.jpg
1-16305
PUGET ENERGY, INC.
A Washington Corporation
10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004
(425) 454-6363
91-1969407
psd-20220930_g2.jpg
1-4393
PUGET SOUND ENERGY, INC.
A Washington Corporation
10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004
(425) 454-6363
91-0374630

Securities Registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each classTrading Symbol(s)Name of each exchange on which registered
N/AN/AN/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 and posted on their corporate websites, if any, every interactiveInteractive Data File required to be submitted and posted 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, or a smaller reporting company or an emerging growth company.  See definitionthe definitions of “large accelerated filer", "accelerated filer, accelerated filer and" a smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Puget Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filerFiler/X/Smaller reporting company/  /Emerging growth company/  /
Puget Sound Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filerFiler/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
3
4
4
Page
5
5
Filing Format
4
Forward-Looking Statements
4
Part I.
Financial Information
5
Item 1.
Financial Statements
5
Puget Energy, Inc.
Consolidated Statements of Income – ThreeThree and Nine Months EndedEnded September 30, 20172022 and 20162021
5
6
7
8
89
Puget Sound Energy, Inc.
912
1011
1112
13
1314
Notes
1415
35
5370
5370
5471
5471
5471
Item 5.Other Information
54
5571
Exhibit Index
56
Signatures
57


DEFINITIONS

AROAsset Retirement and Environmental Obligations
ASU
72
73

2

DEFINITIONS
ASUAccounting Standards Update
ASCAccounting Standards Codification
EBITDAEarnings Before Interest, Tax, Depreciation and Amortization
EIMFASBEnergy Imbalance Market
ERFExpedited Rate Filing
FASBFinancial Accounting Standards Board
GAAPU.S. Generally Accepted Accounting Principles
GRCGeneral Rate Case
ISDAInternational Swaps and Derivatives Association
LIBORLondon Interbank Offered Rate
LNGLiquefied Natural Gas
MMBtuOne Million British Thermal Units
MWhMegawatt Hour (one MWh equals one thousand kWh)
NAESBNorth American Energy Standards Board
NPNSNormal Purchase Normal Sale
PCAPower Cost Adjustment
PCORCPower Cost Only Rate Case
PGAPurchased Gas Adjustment
PSEPTCProduction Tax Credit
PSEPuget Sound Energy, Inc.
Puget EnergyPuget Energy, Inc.
Puget HoldingsPuget Holdings LLC
Puget LNGPuget Liquid Natural GasLNG, LLC
REPSERPResidential Exchange Program
SERPSupplemental Executive Retirement Plan
Washington CommissionWashington Utilities and Transportation Commission
WSPPWSPP, 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 productsby-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, andextreme weather conditions, landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
●The impact of widespread health developments, including the global Coronavirus Disease 2019 (COVID-19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, government stay at home orders, restrictions on travel, commercial, social and other activities, and the impact of vaccination mandates on employee and vendor staffing levels) could materially and adversely affect, among other things, electric and natural gas demand, customers’ ability to pay, supply chains, availability of skilled work-force, contract counterparties, liquidity and financial markets;
●Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations)organizations or the decision of companies in the Western Interconnection to join such markets) or other related federal initiatives;
●PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
●The ability to restart generation following a regional transmission disruption;
●The ability of a natural gas or electric plant to operate as intended;
●PSE's resource adequacy needs to meet the Clean Energy Transformation Act (CETA) requirements, through a combination of owned or contracted resources, may significantly increase purchased power and gas costs if pricing pressures and supply constraints on resource acquisitions increase;
●Changes in climate, or weather conditions, or sustained extreme weather events in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;
●The ability to renew contracts for electric and natural gas supply and the price of renewal;
●Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
●The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
●The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
●Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
●Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●Employee workforce factors including strikes,strikes; work stoppages,stoppages; retirements; absences due to pandemics, accidents, natural disasters or other significant, unforeseeable events; availability of qualified employees or the loss of a key executive;
●PSE's service territory operates within a region of high demand for skilled workers resulting in significant competition and inflated wages, which puts pressure on PSE's ability to attract, retain and compensate employees;
●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.thereunder; and
●Recent laws proposed or passed by various municipalities in PSE's service territory, including Seattle, seek to reduce or eliminate the use of natural gas in various contexts, such as for space, cooking, and water heating in new commercial and multifamily buildings. Such laws may impact operations due to costs and delays from incremental permitting and other requirements that are outside PSE's control.


Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  For further information, see Part I, Item 1A, “Risk Factors” in the Company's most recent Annual Report on Form 10-K.10-K for the year ended December 31, 2021.



4

PART I                    FINANCIAL INFORMATION


Item 1.                      Financial Statements


PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)





Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Operating revenue:
Electric$714,122 $613,386 $2,064,830 $1,935,800 
Natural gas128,665 122,808791,067710,838
Other11,086 34,04233,78953,074
Total operating revenue853,873 770,236 2,889,686 2,699,712 
Operating expenses:
Energy costs:
Purchased electricity257,411 190,928708,005558,853
Electric generation fuel105,551 92,883212,693209,749
Residential exchange(15,712)(16,491)(55,565)(59,885)
Purchased natural gas38,821 35,518308,606253,362
Unrealized (gain) loss on derivative instruments, net62,709 (88,517)(59,939)(172,795)
Utility operations and maintenance157,246 143,873488,479454,580
Non-utility expense and other13,279 24,44043,99743,912
Depreciation & amortization166,811 162,743497,063537,104
Conservation amortization25,033 19,23481,08075,195
Taxes other than income taxes71,476 68,471279,397255,618
Total operating expenses882,625 633,082 2,503,816 2,155,693 
Operating income (loss)(28,752)137,154 385,870 544,019 
Other income (expense):
Other income12,899 14,62639,29442,746
Other expense(2,839)(3,317)(10,531)(7,177)
Interest charges:
AFUDC4,591 4,33712,69411,698
Interest expense(85,831)(84,769)(258,493)(264,536)
Income (loss) before income taxes(99,932)68,031 168,834 326,750 
Income tax (benefit) expense(6,222)18,46217,74532,946
Net income (loss)$(93,710)$49,569 $151,089 $293,804 
 Three Months Ended September 30, Nine Months Ended
September 30,
 2017 2016 2017 2016
Operating revenue:       
Electric$537,543
 $495,321
 $1,736,335
 $1,622,664
Natural gas111,516
 114,458
 691,685
 601,309
Other11,318
 8,499
 29,356
 25,170
Total operating revenue660,377
 618,278
 2,457,376
 2,249,143
Operating expenses: 
  
  
  
Energy costs: 
  
  
  
Purchased electricity115,881
 94,849
 425,263
 356,296
Electric generation fuel66,584
 70,503
 152,057
 165,627
Residential exchange(14,246) (15,577) (52,814) (49,093)
Purchased natural gas32,224
 34,041
 248,208
 205,418
Unrealized (gain) loss on derivative instruments, net(23) 6,327
 23,098
 (57,218)
Utility operations and maintenance141,003
 138,265
 438,622
 422,273
Non-utility expense and other7,319
 4,708
 18,658
 15,520
Depreciation and amortization120,829
 110,022
 355,538
 328,809
Conservation amortization25,395
 21,800
 85,847
 77,551
Taxes other than income taxes66,367
 65,268
 262,099
 235,431
Total operating expenses561,333
 530,206
 1,956,576
 1,700,614
Operating income (loss)99,044
 88,072
 500,800
 548,529
Other income (expense): 
  
  
  
Other income7,151
 6,130
 19,375
 19,187
Other expense(2,878) (5,025) (6,134) (8,488)
Non-hedged interest rate swap (expense) income—
 563
 28
 (651)
Interest charges: 
  
  
  
AFUDC3,123
 2,702
 7,853
 7,663
Interest expense(88,780) (89,297) (265,771) (266,786)
Income (loss) before income taxes17,660
 3,145
 256,151
 299,454
Income tax (benefit) expense4,824
 810
 80,489
 91,380
Net income (loss)$12,836
 $2,335
 $175,662
 $208,074


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
September 30,		Nine Months Ended
September 30,
 2022202120222021
Net income (loss)$(93,710)$49,569 $151,089 $293,804 
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $768, $427, $1,743 and $1,695, respectively2,896 1,608 6,558 6,379 
Other comprehensive income (loss)2,896 1,608 6,558 6,379 
Comprehensive income (loss)$(90,814)$51,177 $157,647 $300,183 
 Three Months Ended September 30, Nine Months Ended
September 30,
 2017 2016 2017 2016
Net income (loss)$12,836
 $2,335
 $175,662
 $208,074
Other comprehensive income (loss): 
  
 

  
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $(143), $(16), $216 and $(216), respectively(266) (29) 400
 (400)
Other comprehensive income (loss)(266) (29) 400
 (400)
Comprehensive income (loss)$12,570
 $2,306
 $176,062
 $207,674

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

PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



ASSETS
 September 30,
2017		 December 31,
2016
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):   
Electric plant$7,918,877
 $7,673,772
Natural gas plant3,253,977
 3,051,586
Common plant738,409
 594,994
Less: Accumulated depreciation and amortization(2,409,508) (2,161,796)
Net utility plant9,501,755
 9,158,556
Other property and investments: 
  
Goodwill1,656,513
 1,656,513
Other property and investments166,996
 106,418
Total other property and investments1,823,509
 1,762,931
Current assets: 
  
Cash and cash equivalents6,768
 28,878
Restricted cash9,302
 12,418
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively232,699
 329,375
Unbilled revenue126,252
 234,053
Purchased gas adjustment receivable—
 2,785
Materials and supplies, at average cost108,814
 106,378
Fuel and natural gas inventory, at average cost60,645
 58,181
Unrealized gain on derivative instruments16,605
 54,341
Prepaid expense and other35,655
 43,046
Power contract acquisition adjustment gain15,932
 33,413
Total current assets612,672
 902,868
Other long-term and regulatory assets: 
  
Regulatory asset for deferred income taxes71,566
 72,038
Power cost adjustment mechanism4,540
 4,531
Regulatory assets related to power contracts19,998
 22,613
Other regulatory assets1,014,796
 1,034,348
Unrealized gain on derivative instruments2,877
 8,738
Power contract acquisition adjustment gain163,588
 241,648
Other65,138
 58,109
Total other long-term and regulatory assets1,342,503
 1,442,025
Total assets$13,280,439
 $13,266,380


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





6
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



CAPITALIZATION AND LIABILITIES
 September 30,
2017		 December 31,
2016
Capitalization:   
Common shareholder’s equity:   
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding$—
 $—
Additional paid-in capital3,308,957
 3,308,957
Retained earnings571,588
 413,468
Accumulated other comprehensive income (loss), net of tax(33,312) (33,712)
Total common shareholder’s equity3,847,233
 3,688,713
Long-term debt: 
  
First mortgage bonds and senior notes3,164,412
 3,362,000
Pollution control bonds161,860
 161,860
Junior subordinated notes250,000
 250,000
Long-term debt1,883,064
 1,812,480
Debt discount, issuance costs and other(224,336) (234,679)
Total long-term debt5,235,000
 5,351,661
Total capitalization9,082,233
 9,040,374
Current liabilities: 
  
Accounts payable296,659
 317,043
Short-term debt139,000
 245,763
Current maturities of long-term debt200,000
 2,412
Purchased gas adjustment payable5,784
 —
Accrued expenses: 
  
  Taxes81,354
 111,428
  Salaries and wages41,121
 49,749
  Interest79,213
 73,610
Unrealized loss on derivative instruments49,820
 44,310
Power contract acquisition adjustment loss2,850
 3,159
Other81,486
 71,996
Total current liabilities977,287
 919,470
Other long-term and regulatory liabilities: 
  
Deferred income taxes1,652,573
 1,570,931
Unrealized loss on derivative instruments15,578
 16,261
Regulatory liabilities611,899
 654,622
Regulatory liabilities related to power contracts179,519
 275,061
Power contract acquisition adjustment loss17,148
 19,454
Other deferred credits744,202
 770,207
Total other long-term and regulatory liabilities3,220,919
 3,306,536
Commitments and contingencies (Note 8)

 

Total capitalization and liabilities$13,280,439
 $13,266,380

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


 PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 Nine Months Ended
September 30,
 2017 2016
Operating activities:   
Net income (loss)$175,662
 $208,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
Depreciation and amortization355,538
 328,809
Conservation amortization85,847
 77,551
Deferred income taxes and tax credits, net81,899
 90,828
Net unrealized (gain) loss on derivative instruments22,957
 (60,785)
AFUDC – equity(11,266) (10,769)
Funding of pension liability(18,000) (24,000)
Regulatory assets and liabilities(83,370) (138,096)
Other long-term assets and liabilities8,275
 30,766
Change in certain current assets and liabilities: 
  
Accounts receivable and unbilled revenue204,477
 175,627
Materials and supplies(2,436) (28,448)
Fuel and natural gas inventory(2,789) (3,222)
Prepayments and other7,391
 (29,352)
Purchased gas adjustment8,569
 (10,743)
Accounts payable(31,027) (22,874)
Taxes payable(30,074) (36,411)
Other(2,983) 23,391
Net cash provided by (used in) operating activities768,670
 570,346
Investing activities: 
  
Construction expenditures – excluding equity AFUDC(761,968) (507,703)
Restricted cash3,116
 (1,391)
Other5,796
 (1,781)
Net cash provided by (used in) investing activities(753,056) (510,875)
Financing activities: 
  
Change in short-term debt, net(106,763) 12,996
Dividends paid(17,543) (111,592)
Proceeds from long-term debt and bonds issued70,583
 —
Other15,999
 13,479
Net cash provided by (used in) financing activities(37,724) (85,117)
Net increase (decrease) in cash and cash equivalents(22,110) (25,646)
Cash and cash equivalents at beginning of period28,878
 42,494
Cash and cash equivalents at end of period$6,768
 $16,848
Supplemental cash flow information: 
  
Cash payments for interest (net of capitalized interest)$239,566
 $241,351
Cash payments (refunds) for income taxes1,649
 —
Non-cash financing and investing activities:   
Accounts payable for capital expenditures eliminated from cash flows$87,456
 $58,278
PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



ASSETS
September 30,
2022		December 31, 2021
Utility plant (at original cost, including construction work in progress of $865,563 and $870,204 respectively):
Electric plant$10,150,577 $9,729,643 
Natural gas plant4,659,314 4,498,198 
Common plant1,115,852 1,155,567 
Less: Accumulated depreciation and amortization(4,278,241)(4,031,458)
Net utility plant11,647,502 11,351,950 
Other property and investments:
Goodwill1,656,513 1,656,513 
Other property and investments326,306 324,897 
Total other property and investments1,982,819 1,981,410 
Current assets:
Cash and cash equivalents49,304 56,946 
Restricted cash12,436 46,204 
Accounts receivable, net of allowance for doubtful accounts of $39,332 and $34,958, respectively388,638 398,895 
Unbilled revenue158,591 271,606 
Materials and supplies, at average cost127,290 113,287 
Fuel and natural gas inventory, at average cost104,812 59,393 
Unrealized gain on derivative instruments212,583 128,210 
Prepaid expense and other52,945 46,293 
Power contract acquisition adjustment gain17,185 17,274 
Total current assets1,123,784 1,138,108 
Other long-term and regulatory assets:
Power cost adjustment mechanism49,029 79,546 
Purchased gas adjustment receivable49,426 57,935 
Regulatory assets related to power contracts8,179 9,689 
Other regulatory assets789,147 815,058 
Unrealized gain on derivative instruments65,515 26,197 
Power contract acquisition adjustment gain50,157 63,660 
Operating lease right-of-use asset176,568 184,957 
Other192,947 163,374 
Total other long-term and regulatory assets1,380,968 1,400,416 
Total assets$16,135,073 $15,871,884 

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








PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



CAPITALIZATION AND LIABILITIES
September 30,
2022		December 31, 2021
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding$— $— 
Additional paid-in capital3,523,532 3,523,532 
Retained earnings1,217,063 1,067,216 
Accumulated other comprehensive income (loss), net of tax(20,874)(27,432)
Total common shareholder’s equity4,719,721 4,563,316 
Long-term debt:
First mortgage bonds and senior notes4,662,000 4,662,000 
Pollution control bonds161,860 161,860 
Long-term debt2,034,300 1,583,300 
Debt discount issuance costs and other(197,861)(203,394)
Total long-term debt6,660,299 6,203,766 
Total capitalization11,380,020 10,767,082 
Current liabilities:
Accounts payable408,915 444,384 
Short-term debt161,000 140,000 
Current maturities of long-term debt— 450,000 
Accrued expenses:
Taxes114,965 127,398 
Salaries and wages52,829 47,936 
Interest76,839 67,807 
Unrealized loss on derivative instruments71,213 63,309 
Power contract acquisition adjustment loss1,661 1,785 
Operating lease liabilities21,565 20,398 
Other69,490 62,406 
Total current liabilities978,477 1,425,423 
Other long-term and regulatory liabilities:
Deferred income taxes933,421 912,484 
Unrealized loss on derivative instruments49,798 40,965 
Regulatory liabilities948,453 844,184 
Regulatory liability for deferred income taxes829,005 865,976 
Regulatory liabilities related to power contracts67,342 80,934 
Power contract acquisition adjustment loss6,518 7,904 
Operating lease liabilities162,694 172,510 
Finance lease liabilities103,314 105,303
Other deferred credits676,031 649,119 
Total long-term and regulatory liabilities3,776,576 3,679,379 
Commitments and contingencies (Note 8)
Total capitalization and liabilities$16,135,073 $15,871,884 

The accompanying notes are an integral part of the financial statements.
7

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)
Common StockAdditional Paid-in CapitalAccumulated Other Comprehensive Income (Loss)
SharesAmountRetained EarningsTotal Equity
Balance at December 31, 2020200$— $3,313,532 $912,787 $(86,437)$4,139,882 
Net income (loss)———188,993 — 188,993 
Common stock dividend paid———(22,939)— (22,939)
Other comprehensive income (loss)———— 2,385 2,385 
Balance at March 31, 2021200$— $3,313,532 $1,078,841 $(84,052)$4,308,321 
Net income (loss)———55,242 — 55,242 
Common stock dividend paid———(23,214)— (23,214)
Capital contribution——210,000— — 210,000 
Other comprehensive income (loss)———— 2,386 2,386 
Balance at June 30, 2021200$— $3,523,532 $1,110,869 $(81,666)$4,552,735 
Net Income (loss)———49,569—49,569
Common stock dividend paid———(21,914)—(21,914)
Other comprehensive income (loss)————1,6081,608
Balance at September 30, 2021200$— $3,523,532 $1,138,524 $(80,058)$4,581,998 
Balance at December 31, 2021200$— $3,523,532 $1,067,216 $(27,432)$4,563,316 
Net income (loss)———278,295 —278,295 
Common stock dividend paid———(939)—(939)
Other comprehensive income (loss)————1,831 1,831 
Balance at March 31, 2022200$— $3,523,532 $1,344,572 $(25,601)$4,842,503 
Net income (loss)———(33,496)—(33,496)
Common stock dividend paid———(294)—(294)
Other comprehensive income (loss)————1,8311,831
Balance at June 30, 2022200$— $3,523,532 $1,310,782 $(23,770)$4,810,544 
Net income (loss)———(93,710)—(93,710)
Common stock dividend paid———(9)—(9)
Other comprehensive income (loss)————2,8962,896
Balance at September 30, 2022200—$3,523,532 $1,217,063 $(20,874)$4,719,721 

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)
Nine Months Ended
September 30,
20222021
Operating activities:
Net Income (loss)$151,089 $293,804 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization497,063 537,104 
Conservation amortization81,080 75,195 
Deferred income taxes and tax credits, net(17,777)38,095 
Net unrealized (gain) loss on derivative instruments(59,939)(172,795)
AFUDC - equity(21,396)(19,269)
Production tax credit utilization— (45,562)
Other non-cash(15,060)(13,437)
Funding of pension liability(18,000)(18,000)
Regulatory assets and liabilities11,210 (87,076)
Purchased gas adjustment8,509 31,387 
Other long term assets and liabilities(15,042)552 
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue123,272 101,809 
Materials and supplies(14,003)(1,430)
Fuel and natural gas inventory(45,419)(18,224)
Prepayments and other12,048 (22,529)
Accounts payable(30,572)(5,754)
Taxes payable(12,433)4,422 
Other16,525 (7,161)
Net cash provided by (used in) operating activities651,155 671,131 
Investing activities:
Construction expenditures - excluding equity AFUDC(721,812)(662,189)
Other(580)1,076 
Net cash provided by (used in) investing activities(722,392)(661,113)
Financing activities:
Change in short-term debt, net21,000 (373,800)
Dividends paid(1,242)(68,067)
Investment from Parent— 210,000 
Proceeds from long-term debt and bonds issued448,075 961,238 
Redemption of bonds and notes(450,000)(502,414)
Repayment of term loan and revolving credit— (234,000)
Other11,994 31,202 
Net cash provided by (used in) financing activities29,827 24,159 
Net increase (decrease) in cash, cash equivalents, and restricted cash(41,410)34,177 
Cash, cash equivalents, and restricted cash at beginning of period103,150 81,851 
Cash, cash equivalents, and restricted cash at end of period$61,740 $116,028 
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$225,576 $237,348 
Cash payments (refunds) for income taxes35,013 16,861 
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$70,610 $69,909 
Recognition of finance lease eliminated from cash flows454 44,347 

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
September 30,		Nine Months Ended
September 30,
2022202120222021
Operating revenue:
Electric$714,122 $613,386 $2,064,830 $1,935,800 
Natural gas128,665 122,808 791,067 710,838 
Other10,548 34,042 33,216 53,074 
Total operating revenue853,335 770,236 2,889,113 2,699,712 
Operating expenses:
Energy costs:
Purchased electricity257,411 190,928 708,005 558,853 
Electric generation fuel105,551 92,883 212,693 209,749 
Residential exchange(15,712)(16,491)(55,565)(59,885)
Purchased natural gas38,821 35,518 308,606 253,362 
Unrealized (gain) loss on derivative instruments, net62,709 (88,517)(59,939)(172,795)
Utility operations and maintenance157,246 143,873 488,479 454,580 
Non-utility expense and other10,673 23,920 35,329 42,290 
Depreciation & amortization165,141 162,629 492,854 536,794 
Conservation amortization25,033 19,234 81,080 75,195 
Taxes other than income taxes71,099 68,471 278,458 255,618 
Total operating expenses877,972 632,448 2,490,000 2,153,761 
Operating income (loss)(24,637)137,788 399,113 545,951 
Other income (expense):
Other income10,731 11,937 32,704 34,398 
Other expense(2,839)(3,317)(10,531)(7,177)
Interest charges:
AFUDC4,591 4,337 12,694 11,698 
Interest expense(64,139)(57,718)(189,946)(182,958)
Income (loss) before income taxes(76,293)93,027 244,034 401,912 
Income tax (benefit) expense(8,480)18,902 30,084 49,953 
Net income (loss)$(67,813)$74,125 $213,950 $351,959 

 Three Months Ended September 30, Nine Months Ended
September 30,
 2017 2016 2017 2016
Operating revenue:       
Electric$537,543
 $495,321
 $1,736,335
 $1,622,664
Natural gas111,516
 114,458
 691,685
 601,309
Other11,318
 8,815
 29,356
 25,487
Total operating revenue660,377
 618,594
 2,457,376
 2,249,460
Operating expenses: 
  
    
Energy costs: 
  
    
Purchased electricity115,881
 94,849
 425,263
 356,296
Electric generation fuel66,584
 70,503
 152,057
 165,627
Residential exchange(14,246) (15,577) (52,814) (49,093)
Purchased natural gas32,224
 34,041
 248,208
 205,418
Unrealized (gain) loss on derivative instruments, net(23) 6,327
 23,098
 (57,218)
Utility operations and maintenance141,003
 138,265
 438,622
 422,273
Non-utility expense and other9,994
 8,620
 27,857
 26,474
Depreciation and amortization120,829
 110,022
 355,538
 328,809
Conservation amortization25,395
 21,800
 85,847
 77,551
Taxes other than income taxes66,367
 65,268
 262,099
 235,431
Total operating expenses564,008
 534,118
 1,965,775
 1,711,568
Operating income (loss)96,369
 84,476
 491,601
 537,892
Other income (expense): 
  
    
Other income6,778
 6,131
 18,861
 19,184
Other expense(2,878) (5,025) (6,134) (8,488)
Interest charges: 
  
    
AFUDC3,123
 2,702
 7,853
 7,663
Interest expense(59,868) (60,914) (180,320) (182,336)
Income (loss) before income taxes43,524
 27,370
 331,861
 373,915
Income tax (benefit) expense14,424
 8,393
 109,015
 117,533
Net income (loss)$29,100
 $18,977
 $222,846
 $256,382



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
September 30,		Nine Months Ended
September 30,
 2022202120222021
Net income (loss)$(67,813)$74,125 $213,950 $351,959 
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,233 and $1,000, $3,139 and $3,369, respectively4,639 3,757 11,814 12,674
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $25, $76 and $77, respectively95 97 290 289 
Other comprehensive income (loss)4,734 3,854 12,104 12,963 
Comprehensive income (loss)$(63,079)$77,979 $226,054 $364,922 
 Three Months Ended September 30, Nine Months Ended
September 30,
 2017 2016 2017 2016
Net income (loss)$29,100
 $18,977
 $222,846
 $256,382
Other comprehensive income (loss): 
  
  
  
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $939, $1,422, $3,813 and $3,942, respectively1,744
 2,642
 7,083
 7,322
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $128 and $128, respectively79
 79
 237
 237
Other comprehensive income (loss)1,823
 2,721
 7,320
 7,559
Comprehensive income (loss)$30,923
 $21,698
 $230,166
 $263,941


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

11

PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)






ASSETS
September 30,
2022		December 31, 2021
Utility plant (at original cost, including construction work in progress of $865,563 and $870,204, respectively):
Electric plant$11,930,798 $11,535,976 
Natural gas plant5,214,015 5,054,622 
Common plant1,137,473 1,177,598 
Less:  Accumulated depreciation and amortization(6,634,784)(6,416,246)
Net utility plant11,647,502 11,351,950 
Other property and investments:
Other property and investments79,003 74,602 
Total other property and investments79,003 74,602 
Current assets:
Cash and cash equivalents44,759 50,043 
Restricted cash12,436 46,204 
Accounts receivable, net of allowance for doubtful accounts of $39,332 and $34,958, respectively389,694 402,602 
Unbilled revenue158,054 271,606 
Materials and supplies, at average cost127,290 113,287 
Fuel and natural gas inventory, at average cost102,918 58,129 
Unrealized gain on derivative instruments212,583 128,210 
Prepaid expense and other52,945 46,293 
Total current assets1,100,679 1,116,374 
Other long-term and regulatory assets:
Power cost adjustment mechanism49,029 79,546 
Purchased gas adjustment receivable49,426 57,935 
Other regulatory assets789,147 815,058 
Unrealized gain on derivative instruments65,515 26,197 
Operating lease right-of-use asset176,568 184,957 
Other189,403 162,391 
Total other long-term and regulatory assets1,319,088 1,326,084 
Total assets$14,146,272 $13,869,010 
 September 30,
2017		 December 31,
2016
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):   
Electric plant$10,036,204
 $9,813,169
Natural gas plant3,838,533
 3,640,271
Common plant776,116
 632,718
Less:  Accumulated depreciation and amortization(5,149,098) (4,927,602)
Net utility plant9,501,755
 9,158,556
Other property and investments: 
  
Other property and investments78,332
 77,960
Total other property and investments78,332
 77,960
Current assets: 
  
Cash and cash equivalents5,939
 28,481
Restricted cash9,302
 12,418
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively237,091
 344,964
Unbilled revenue126,252
 234,053
Purchased gas adjustment receivable—
 2,785
Materials and supplies, at average cost108,814
 106,378
Fuel and natural gas inventory, at average cost59,640
 56,851
Unrealized gain on derivative instruments16,605
 54,341
Prepaid expense and other35,655
 43,046
Total current assets599,298
 883,317
Other long-term and regulatory assets: 
  
Regulatory asset for deferred income taxes71,057
 71,517
Power cost adjustment mechanism4,540
 4,531
Other regulatory assets1,014,804
 1,034,352
Unrealized gain on derivative instruments2,877
 8,738
Other65,138
 58,109
Total other long-term and regulatory assets1,158,416
 1,177,247
Total assets$11,337,801
 $11,297,080


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











PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)




CAPITALIZATION AND LIABILITIES

September 30,
2022		December 31, 2021
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding$859 $859 
Additional paid-in capital3,535,105 3,485,105 
Retained earnings1,176,125 982,607 
Accumulated other comprehensive income (loss), net of tax(101,037)(113,141)
Total common shareholder’s equity4,611,052 4,355,430 
Long-term debt:
First mortgage bonds and senior notes4,662,000 4,662,000 
Pollution control bonds161,860 161,860 
Debt discount, issuance costs and other(37,585)(39,141)
Total long-term debt4,786,275 4,784,719 
Total capitalization9,397,327 9,140,149 
Current liabilities:
Accounts payable408,829 451,716 
Short-term debt102,000 140,000 
Accrued expenses:
Taxes115,663 133,406 
Salaries and wages52,829 47,936 
Interest58,395 51,832 
Unrealized loss on derivative instruments71,213 63,309 
Operating lease liabilities21,565 20,398 
Other69,490 62,406 
Total current liabilities899,984 971,003 
Other long-term and regulatory liabilities:
Deferred income taxes1,084,184 1,084,203 
Unrealized loss on derivative instruments49,798 40,965 
Regulatory liabilities947,189 842,920 
Regulatory liabilities for deferred income tax829,561 866,541 
Operating lease liabilities162,694 172,510 
Finance lease liabilities103,314 105,303 
Other deferred credits672,221 645,416 
Total long-term and regulatory liabilities3,848,961 3,757,858 
Commitments and contingencies (Note 8)
Total capitalization and liabilities$14,146,272 $13,869,010 

 September 30,
2017		 December 31,
2016
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 capital3,275,105
 3,275,105
Retained earnings486,095
 359,795
Accumulated other comprehensive income (loss), net of tax(138,191) (145,511)
Total common shareholder’s equity3,623,868
 3,490,248
Long-term debt: 
  
First mortgage bonds and senior notes3,164,412
 3,362,000
Pollution control bonds161,860
 161,860
Junior subordinated notes250,000
 250,000
Debt discount, issuance costs and other(27,043) (28,974)
Total long-term debt3,549,229
 3,744,886
Total capitalization7,173,097
 7,235,134
Current liabilities: 
  
Accounts payable296,659
 317,043
Short-term debt139,000
 245,763
Current maturities of long-term debt200,000
 2,412
Purchased gas adjustment payable5,784
 —
Accrued expenses: 
  
Taxes81,354
 111,428
Salaries and wages41,121
 49,749
Interest56,254
 48,087
       Unrealized loss on derivative instruments49,820
 44,170
       Other81,486
 71,996
Total current liabilities951,478
 890,648
Other long-term and regulatory liabilities: 
  
Deferred income taxes1,844,886
 1,732,390
Unrealized loss on derivative instruments15,578
 16,261
Regulatory liabilities610,902
 653,296
Other deferred credits741,860
 769,351
Total other long-term and regulatory liabilities3,213,226
 3,171,298
Commitments and contingencies (Note 8)

 

Total capitalization and liabilities$11,337,801
 $11,297,080


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

12

 PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)
Common StockAdditional Paid-in CapitalAccumulated Other Comprehensive Income (Loss)
SharesAmountRetained EarningsTotal Equity
Balance at December 31, 202085,903,791$859 $3,485,105 $876,401 $(180,956)$4,181,409 
Net income (loss)—— — 199,470 — 199,470 
Common stock dividend paid—— — (52,053)— (52,053)
Other comprehensive income (loss)—— — — 4,554 4,554 
Balance at March 31, 202185,903,791$859 $3,485,105 $1,023,818 $(176,402)$4,333,380 
Net income (loss)—— — 78,364 — 78,364 
Common stock dividend paid—— — (44,622)— (44,622)
Other comprehensive income (loss)—— — — 4,555 4,555 
Balance at June 30, 202185,903,791$859 $3,485,105 $1,057,560 $(171,847)$4,371,677 
Net income (loss)—— — 74,125 — 74,125 
Common stock dividend paid—— — (74,170)— (74,170)
Other comprehensive income (loss)—— — — 3,854 3,854 
Balance at September 30, 202185,903,791$859 $3,485,105 $1,057,515 $(167,993)$4,375,486 
Balance at December 31, 202185,903,791$859 $3,485,105 $982,607 $(113,141)$4,355,430 
Net income (loss)—— — 288,081 — 288,081 
Common stock dividend paid—— — (13,896)— (13,896)
Other comprehensive income (loss)—— — — 3,685 3,685 
Balance at March 31, 202285,903,791$859 $3,485,105 $1,256,792 $(109,456)$4,633,300 
Net income (loss)— — — (6,318)— (6,318)
Common stock dividend paid— — — (2,037)— (2,037)
Other comprehensive income (loss)— — — — 3,685 3,685 
Balance at June 30, 202285,903,791$859 $3,485,105 $1,248,437 $(105,771)$4,628,630 
Net income (loss)— — — (67,813)— (67,813)
Common stock dividend paid— — — (4,499)— (4,499)
Capital contribution— — 50,000 — — 50,000 
Other comprehensive income (loss)— — — — 4,734 4,734 
Balance at September 30, 202285,903,791$859 $3,535,105 $1,176,125 $(101,037)$4,611,052 

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


13

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,
20222021
Operating activities:
Net Income (loss)$213,950 $351,959 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization492,854 536,794 
Conservation amortization81,080 75,195 
Deferred income taxes and tax credits, net(40,216)38,718 
Net unrealized (gain) loss on derivative instruments(59,939)(172,795)
AFUDC - equity(21,396)(19,269)
Production tax credit utilization— (45,562)
Other non-cash(23,189)(21,497)
Funding of pension liability(18,000)(18,000)
Regulatory assets and liabilities11,210 (87,076)
Purchased gas adjustment8,509 31,387 
Other long term assets and liabilities(8,034)8,516 
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue126,460 102,763 
Materials and supplies(14,003)(1,430)
Fuel and natural gas inventory(44,789)(18,224)
Prepayments and other12,048 (22,529)
Accounts payable(37,990)4,169 
Taxes payable(17,743)7,448 
Other14,055 (4,127)
Net cash provided by (used in) operating activities674,867 746,440 
Investing activities:
Construction expenditures - excluding equity AFUDC(720,703)(654,182)
Other(580)1,076 
Net cash provided by (used in) investing activities(721,283)(653,106)
Financing activities:
Change in short-term debt, net(38,000)(373,800)
Dividends paid(20,432)(170,845)
Investment from Parent50,000 — 
Proceeds from long-term debt and bonds issued— 446,063 
Redemption of bonds and notes— (2,414)
Other15,796 32,589 
Net cash provided by (used in) financing activities7,364 (68,407)
Net increase (decrease) in cash, cash equivalents, and restricted cash(39,052)24,927 
Cash, cash equivalents, and restricted cash at beginning of period96,247 80,721 
Cash, cash equivalents, and restricted cash at end of period$57,195 $105,648 
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$167,099 $157,699 
Cash payments (refunds) for income taxes75,100 28,744 
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$70,610 $69,909 
Recognition of finance lease eliminated from cash flows454 44,347 

 Nine Months Ended
September 30,
 2017 2016
Operating activities:   
Net income (loss)$222,846
 $256,382
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
Depreciation and amortization355,538
 328,809
Conservation amortization85,847
 77,551
Deferred income taxes and tax credits, net109,015
 116,982
Net unrealized (gain) loss on derivative instruments23,098
 (57,218)
AFUDC – equity(11,266) (10,769)
Funding of pension liability(18,000) (24,000)
Regulatory assets and liabilities(83,370) (138,096)
Other long-term assets and liabilities(15,734) 34,128
Change in certain current assets and liabilities: 
  
Accounts receivable and unbilled revenue215,674
 175,733
Materials and supplies(2,436) (28,448)
Fuel and natural gas inventory(2,789) (3,222)
Prepayments and other7,391
 (29,352)
Purchased gas adjustment8,569
 (10,743)
Accounts payable(31,027) (22,874)
Taxes payable(30,074) (36,411)
Other(857) 22,035
Net cash provided by (used in) operating activities832,425
 650,487
Investing activities: 
  
Construction expenditures – excluding equity AFUDC(677,004) (507,703)
Restricted cash3,116
 (1,391)
Other6,233
 2,519
Net cash provided by (used in) investing activities(667,655) (506,575)
Financing activities: 
  
Change in short-term debt, net(106,763) 12,996
Dividends paid(96,546) (195,865)
Other15,997
 13,510
Net cash provided by (used in) financing activities(187,312) (169,359)
Net increase (decrease) in cash and cash equivalents(22,542) (25,447)
Cash and cash equivalents at beginning of period28,481
 41,856
Cash and cash equivalents at end of period$5,939
 $16,409
Supplemental cash flow information: 
  
Cash payments for interest (net of capitalized interest)$160,426
 $162,091
Cash payments (refunds) for income taxes3,058
 —
Non-cash financing and investing activities:   
Accounts payable for capital expenditures eliminated from cash flows$87,456
 $58,278

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

14



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)



(1)Summary of Consolidation and Significant Accounting Policy
(1)Summary of Consolidation Policy


Basis of Presentation
Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE).PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction.liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur underare incurred by PSE and are allocated to Puget LNG are related party transactions by nature. As of September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.
In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations”, (ASC 805), 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.”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 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.


Allowance for Credit Losses
Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, natural gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.
The allowance increased during both periods due to both an increase in the provision combined with a reduction in receivables charged-off during the period. The Ratepayer Assistance and Preservation of Essential Services proclamation issued by the Washington State governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment. This moratorium ended on September 30, 2021, however, customer disconnects were only performed with approval from the Washington Utilities and Transportation Commission (Washington Commission). Effective October 1, 2022, Washington Commission approval for customer disconnections was no longer required.
The following table presents the activity in the allowance for credit losses for accounts receivable for the nine months ended September 30, 2022 and 2021:
Puget Energy and
Puget Sound Energy		Nine Months
Ended September 30,
(Dollars in Thousands)20222021
Allowance for credit losses:
Beginning balance$34,958 $20,080 
Provision for credit loss expense 1
18,874 26,424 
Receivables charged-off(14,500)(8,728)
Total ending allowance balance$39,332 $37,776 
_______________
1 $4.7 million and $8.5 million of provision were deferred as cost specific to COVID-19 for the nine months ended September 30, 2022 and 2021, respectively.
15

Tacoma LNG Facility
On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. In December 2019, the Puget Sound Clean Air Agency issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. The Tacoma LNG facility is expectedmarket at a lower cost due to be operational in 2019. the facility's scale.
Pursuant to an order by the Washington Commission’s order, Puget LNGCommission, 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 thecommon capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0%to Puget LNG. Per this allocation of the capitalcosts, $245.3 million and operating costs.
For Puget Energy, $86.4$244.7 million inof non-utility plant and construction work in progress related to Puget LNG’sLNG's portion of the Tacoma LNG facility is reported in the “OtherPuget Energy "Other property and investments”investments" line item as of September 30, 2022 and December 31, 2021, respectively. Additionally, $7.8 million and $0.9 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item. For PSE,item for the nine months ended September 30, 2022, and September 30, 2021, respectively. Further, $242.2 million and $239.6 million of natural gas plant and construction work in progress of $76.3 million 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 September 30, 2022 and December 31, 2021, respectively, as PSE is a regulated entity.


Variable Interest Entities
(2)  New Accounting Pronouncements

Revenue Recognition
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from ContractsOn April 12, 2017, PSE entered into a power purchase agreement (PPA) with Customers (Topic 606)". ASU 2014-09Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and, the related amendments outlineonce completed, sell bundled energy and associated attributes, namely renewable energy certificates (RECs) to PSE over a single comprehensive model for useterm of 20 years. Skookumchuck commenced commercial operation in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The Accounting Standards Update (ASU)November 2020. PSE has no equity investment in Skookumchuck but is basedSkookumchuck’s only customer. Based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.
In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferralterms of the Effective Date", deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to early adopt ASU 2014-09 using the original effective date.

The Companycontract, PSE will adopt ASU 2014-09 during the first quarter of fiscal year 2018 by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of retained earnings, effective January 1, 2018. In preparation for adoptionreceive all of the standard, the Company has evaluated key accounting assessments related to the standard. Asoutput of the datefacility, subject to curtailment rights. PSE has concluded that Skookumchuck is a variable interest entity (VIE) and that PSE is not the primary beneficiary of this report,VIE since it does not control the Company hascommercial and operating activities of the facility. Additionally, PSE does not identified material differenceshave the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $10.0 million and $12.3 million were recognized in revenue recognition between current GAAP and ASU 2014-09 and as a result, the Company has not identified material cumulative adjustments necessary. The Company's primary revenue sources are from rate-regulated sales ofpurchased electricity and natural gas to retail customers where revenue is recognized over time as delivered. The Company will include a change in the presentation of alternative revenue program revenue ofon the Company's consolidated statementstatements of income as well as expanded disclosure around the disaggregation of revenue.

Lease Accounting
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.
This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. The Company is considering whether the new guidance will affect the accounting for purchase power agreements, easements and rights–of–way, utility pole attachments, and other utility industry–related arrangements.

Statement of Cash Flows
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle.
This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.
In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented and does not anticipate the new guidance will have a material impact on the consolidated statement of cash flows.

Definition of a Business
In January 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business". This ASU clarifies the definition of a business by providing a screen test to determine when a set of acquired assets is not a business. The test requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of acquired assets is not a business. This test reduces the number of transactions that need to be further evaluated. This ASU affects all companies and other reporting organizations that must determine whether they have acquired or sold a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.

This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company will adopt ASU 2017-01 during the first quarter of fiscal year 2018 and do not expect any impacts on the consolidated financial statements.

Retirement Benefits
In March 2017, the FASB issued ASU 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost". The amendments require 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. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.
This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018. For the periods presented in the income statement, the Company’s non-service components for the nine months ended September 30, 2017,2022 and September 30, 2021, respectively. Additionally, $1.3 million and $2.7 million were included in accounts payable on the Company's balance sheet as of September 30, 2022 and December 31, 2021, respectively.
On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $10.6 million was a creditrecognized in purchased electricity on the Company's consolidated statements of $13.8income for the nine months ended September 30, 2022. Additionally, $2.5 million for Puget Energywas included in accounts payable on the Company's balance sheet as of September 30, 2022.

(2)  New Accounting Pronouncements

Reference Rate Reform
In March 2020, the FASB issued Accounting Standards Update (ASU) 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020). ASU 2020-04 provides temporary optional expedients and $3.5 million for PSE.exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The non-service cost components are in an income positionCompany has promissory notes that reference LIBOR. As of September 30, 2022, the Company has not utilized any of the expedients discussed within this ASU; however, it continues to assess other agreements to determine if LIBOR is included and willif the expedients would be presented inutilized through the other income section, upon adoption.allowed period of December 2022.



16

(3) Revenue

The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the three months ended September 30, 2022 and September 30, 2021:
Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Three Months Ended September 30, 2022
Revenue from contracts with customers:ElectricNatural Gas
Other1
Total
Retail
Residential$276,358 $72,423 $— $348,781 
Commercial232,777 40,577 — 273,354 
Industrial29,162 3,384 — 32,546 
Other4,481 — — 4,481 
Wholesale130,998 — — 130,998 
Transmission and transportation11,884 4,664 — 16,548 
Miscellaneous2,795 408 11,086 14,289 
Total revenue from contracts with customers$688,455 $121,456 $11,086 $820,997 
Total other revenue2
25,667 7,209 — 32,876 
Total operating revenue$714,122 $128,665 $11,086 $853,873 
_____________
1 Other includes $0.5 million of Puget LNG revenues recorded at Puget Energy.
2    Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.


Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Three Months Ended September 30, 2021
Revenue from contracts with customers:ElectricNatural GasOtherTotal
Retail
Residential$259,794 $73,759 $— $333,553 
Commercial217,355 38,763 — 256,118 
Industrial26,779 2,902 — 29,681 
Other4,548 36 — 4,584 
Wholesale72,777 — — 72,777 
Transmission and transportation13,802 4,730 — 18,532 
Miscellaneous12,234 3,543 34,042 49,819 
Total revenue from contracts with customers$607,289 $123,733 $34,042 $765,064 
Total other revenue1
6,097 (925)— 5,172 
Total operating revenue$613,386 $122,808 $34,042 $770,236 
_____________
1    Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers.

17

The following tables present disaggregated revenue from contracts with customers and other revenue by major source for the nine months ended September 30, 2022 and September 30, 2021:

Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Nine Months Ended September 30, 2022
Revenue from contracts with customers:ElectricNatural Gas
Other1
Total
Retail
Residential$989,873 $524,219 $— $1,514,092 
Commercial716,366 233,831 — 950,197 
Industrial86,946 16,590 — 103,536 
Other13,738 — — 13,738 
Wholesale168,206 — — 168,206 
Transmission and transportation33,739 15,198 — 48,937 
Miscellaneous7,964 770 33,789 42,523 
Total revenue from contracts with customers$2,016,832 $790,608 $33,789 $2,841,229 
Total other revenue2
47,998 459 — 48,457 
Total operating revenue$2,064,830 $791,067 $33,789 $2,889,686 
_____________
1 Other includes $0.6 million of Puget LNG revenues recorded at Puget Energy.
2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Nine Months Ended September 30, 2021
Revenue from contracts with customers:ElectricNatural GasOtherTotal
Retail
Residential$931,676 $471,573 $— $1,403,249 
Commercial653,800 195,047 — 848,847 
Industrial80,155 14,672 — 94,827 
Other14,655 392 — 15,047 
Wholesale123,642 — — 123,642 
Transmission and transportation32,478 14,760 — 47,238 
Miscellaneous44,718 10,239 53,074 108,031 
Total revenue from contracts with customers$1,881,124 $706,683 $53,074 $2,640,881 
Total other revenue1
54,676 4,155 — 58,831 
Total operating revenue$1,935,800 $710,838 $53,074 $2,699,712 
_____________
1 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers.

18

Transaction Price Allocated to Remaining Performance Obligations
In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a 10-year delivery period beginning April 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:
Puget Energy
(Dollars in Thousands)20242025202620272028ThereafterTotal
Remaining Performance Obligations$15,359 $19,710 $19,454 $19,454 $19,454 $102,135 $195,566 

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

(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 ofin 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. As of September 30, 2017, the Company did not have any outstanding interest rate swap instruments.

19

The following table presents the volumes, fair values and locationsclassification of the Company's derivative instruments recorded on the balance sheets:
Puget Energy and
Puget Sound Energy
           
 At September 30, 2017 At December 31, 2016
(Dollars in Thousands)Volumes 
Assets1
 
Liabilities2
 Volumes 
Assets1
 
Liabilities2
Interest rate swap derivatives3
$—
 $—
 $—
 $450 million $—
 $141
Electric portfolio derivatives* 11,656
 39,622
 * 36,460
 41,329
Natural gas derivatives (MMBtus)4
305.3 million 7,826
 25,776
 336.4 million 26,619
 19,101
Total derivative contracts** $19,482
 $65,398
 ** $63,079
 $60,571
Current** $16,605
 $49,820
 ** $54,341
 $44,310
Long-term** 2,877
 15,578
 ** 8,738
 16,261
Total derivative contracts** $19,482
 $65,398
 ** $63,079
 $60,571
Puget Energy and
Puget Sound Energy
September 30, 2022December 31, 2021
(Dollars in Thousands)Volumes (millions)
Assets1
Liabilities2
Volumes (millions)
Assets1
Liabilities2
Electric portfolio derivatives*$146,637 $97,291 *$74,829 $85,424 
Natural gas derivatives (MMBtus)3
314131,461 23,720 34779,578 18,850 
Total derivative contracts$278,098 $121,011 $154,407 $104,274 
Current$212,583 $71,213 $128,210 $63,309 
Long-term65,515 49,798 26,197 40,965 
Total derivative contracts$278,098 $121,011 $154,407 $104,274 
_______________
1
Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.
2
Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments.
3
Interest rate swap contracts are only held at Puget Energy, and matured January 2017.
4
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 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017, and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.
**Not meaningful and/or applicable.

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 211.4 million British Thermal Units (MMBtu) and purchased electricity of 6.9 million at September 30, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 4,5, "Fair Value Measurements"Measurements," in the Combined Notes to the consolidated financial statements.Consolidated Financial Statements included in Item 1 of this report.


20

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
Puget Energy and
Puget Sound Energy
At September 30, 2022
Gross Amount Recognized in the Statement of Financial Position1
Gross Amounts Offset in the Statement of Financial PositionNet of Amounts Presented in the Statement of Financial PositionGross Amounts Not Offset in the Statement of Financial Position

(Dollars in Thousands)		Commodity ContractsCash Collateral Received/PostedNet Amount
Assets:
Energy derivative contracts$278,098 $— $278,098 $(41,840)$— $236,258 
Liabilities:
Energy derivative contracts$121,011 $— $121,011 $(41,840)$(2,169)$77,002 
Puget Energy and
Puget Sound Energy
       
 At September 30, 2017
 
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 ContractsCash Collateral Received/Posted Net Amount
Assets:          
Energy derivative contracts$19,482
 $—
 $19,482
 $(12,961)$—
 $6,521
Liabilities:          
Energy derivative contracts65,398
 —
 65,398
 (12,961)(739) 51,698

Puget Energy and
Puget Sound Energy
Puget Energy and
Puget Sound Energy
      Puget Energy and
Puget Sound Energy		At December 31, 2021
At December 31, 2016
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  
Gross Amount Recognized in the Statement of Financial Position1
Gross Amounts Offset in the Statement of Financial PositionNet of Amounts Presented in the Statement of Financial PositionGross Amounts Not Offset in the Statement of Financial Position

(Dollars in Thousands)
 Commodity ContractsCash Collateral Received/Posted Net Amount(Dollars in Thousands)Commodity ContractsCash Collateral Received/PostedNet Amount
Assets:         Assets:
Energy derivative contracts$63,079
 $—
 $63,079
 $(42,858)$—
 $20,221
Energy derivative contracts$154,407 $— $154,407 $(40,833)$— $113,574 
Liabilities:         Liabilities:
Energy derivative contracts60,430
 —
 60,430
 (42,858)—
 17,572
Energy derivative contracts$104,274 $— $104,274 $(40,833)$(1,743)$61,698 
Interest rate swaps2
141
 —
 141
 —
—
 141
_______________
1
All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
2
Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

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



21


The following table presents the effect and locationsclassification 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
September 30,		Nine Months Ended September 30,
(Dollars in Thousands)Classification2022202120222021
Gas for power derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net$(28,197)$42,552 $42,094 $95,421 
RealizedElectric generation fuel73,723 29,404 116,853 40,502 
Power derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net(34,512)45,965 17,845 77,374 
RealizedPurchased electricity4,398 (3,884)11,443 (10,900)
Total gain (loss) recognized in income on derivatives$15,412 $114,037 $188,235 $202,397 
Puget Energy and
Puget Sound Energy		 Three Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)Location2017 2016 2017 2016
Interest rate contracts1:
        
 
Non-hedged interest rate swap
(expense) income
$—
 $563
 $28
 $(651)
 Interest expense—
 (349) —
 (349)
Gas for Power Derivatives:    
    
UnrealizedUnrealized gain (loss) on derivative instruments, net903
 (8,873) (20,979) 41,957
RealizedElectric generation fuel(6,753) (3,194) (14,773) (36,204)
Power Derivatives:        
UnrealizedUnrealized gain (loss) on derivative instruments, net(880) 2,546
 (2,119) 15,261
RealizedPurchased electricity(4,356) (1,282) (14,434) (16,077)
Total gain (loss) recognized in income on derivatives $(11,086) $(10,589) $(52,277) $3,937
_______________
1Interest rate swap contracts are only held at Puget Energy, and matured January 2017.



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 September 30, 2017,2022, approximately 98.5%99.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, wasis with counterparties that are rated at least investment grade by rating agencies and 1.5%0.5% 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. As of September 30, 2017, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transactingalso transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE natural gas exchange (NGX) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2017,2022, PSE had cash posted as collateral of $1.4$4.2 million related to contracts executed on thisthe ICE platform. As additional contracts are executed on this exchange, the amount of collateral to be posted will increase, subject to PSE’s established limit.In August 2022, PSE also hasentered into a $1.0 millionstandby letter of credit posted as

collateralagreement with TD Bank allowing standby letter of credit postings of up to $50.0 million as a condition of transacting on a physical energy exchangethe ICE NGX platform. As of September 30, 2022, PSE had no cash posted with ICE NGX and clearing house in Canada.$15.0 million issued under the standby letter of credit agreement. PSE did not trigger any collateral requirements with any of its counterparties during the nine months ended September 30, 2017 nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.downgrades during the three months ended September 30, 2022.

22

The following table below presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the overall contractual contingent liability positions foramount of additional collateral the Company's derivative activity at September 30, 2017:
Puget Energy and
Puget Sound Energy
           
(Dollars in Thousands)At September 30, 2017 At December 31, 2016
 
Fair Value1
 Posted Contingent 
Fair Value1
 Posted Contingent
Contingent FeatureLiability Collateral Collateral Liability Collateral Collateral
Credit rating2
$6,113
 $—
 $6,113
 $4,894
 $—
 $4,894
Requested credit for adequate assurance27,214
 —
 —
 7,427
 —
 —
Forward value of contract3
739
 1,384
 —
 507
 —
 —
Total$34,066
 $1,384
 $6,113
 $12,828
 $—
 $4,894
Company could be required to post:
Puget Energy and
Puget Sound Energy
(Dollars in Thousands)At September 30, 2022At December 31, 2021
Fair Value1
PostedContingent
Fair Value1
PostedContingent
Contingent FeatureLiabilityCollateralCollateralLiabilityCollateralCollateral
Credit rating2
$61,442 $— $61,442 $52,537 $— $52,537 
Requested credit for adequate assurance6,557 — — 9,380 — — 
Forward value of contract3
2,169 4,151 N/A1,743 12,782 N/A
Total$70,168 $4,151 $61,442 $63,660 $12,782 $52,537 
_______________
1
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
2
Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3
Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

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
(4)Fair Value Measurements

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


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


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


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


Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department, which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily

basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.
The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes or that are transacted at illiquid delivery
23

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


Assets and Liabilities with Estimated Fair Value
The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short termshort-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $49.4of $54.6 million and $49.1$53.2 million at September 30, 20172022 and December 31, 2016,2021 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
The fair value of the junior subordinated and 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 EnergySeptember 30, 2022December 31, 2021
(Dollars in Thousands)LevelCarrying
Value		Fair
Value		Carrying
Value		Fair
Value
Liabilities:
Long-term debt (fixed-rate), net of discount1
2$6,625,999 $6,109,493 $6,170,466 $7,769,896 
Long-term debt (variable-rate)234,300 34,300 33,300 33,300 
Total liabilities$6,660,299 $6,143,793 $6,203,766 $7,803,196 
Puget Energy At September 30, 2017 At December 31, 2016
(Dollars in Thousands)Level
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Liabilities:        
Junior subordinated notes2$250,000
 $246,232
 $250,000
 $210,261
Long-term debt (fixed-rate), net of discount1
25,101,936
 6,439,413
 5,091,593
 6,337,287
Long-term debt (variable-rate)283,064
 83,064
 12,480
 12,480
Total liabilities $5,435,000
 $6,768,709
 $5,354,073
 $6,560,028


Puget Sound Energy At September 30, 2017 At December 31, 2016Puget Sound EnergySeptember 30, 2022December 31, 2021
(Dollars in Thousands)LevelCarrying
Value		 Fair
Value		 Carrying
Value		 Fair
Value		(Dollars in Thousands)LevelCarrying
Value		Fair
Value		Carrying
Value		Fair
Value
Liabilities:        Liabilities:
Junior subordinated notes2$250,000
 $246,232
 $250,000
 $210,261
Long-term debt (fixed-rate), net of discount2
23,499,229
 4,465,126
 3,497,298
 4,360,783
Long-term debt (fixed-rate), net of discount2
2$4,786,275 $4,263,765 $4,784,719 $6,145,639 
Total liabilities $3,749,229
 $4,711,358
 $3,747,298
 $4,571,044
Total liabilities$4,786,275 $4,263,765 $4,784,719 $6,145,639 
_______________
1
The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.
2
The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

1 The carrying value includes debt issuances costs of $22.0 million and $22.7 million for September 30, 2022 and December 31, 2021, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $21.7 million and $22.8 million for September 30, 2022 and December 31, 2021, respectively, which are not included in fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
Puget Energy and
Puget Sound Energy		Fair Value
At September 30, 2022		Fair Value
At December 31, 2021
(Dollars in Thousands)Level 2Level 3TotalLevel 2Level 3Total
Assets:      
Electric derivative instruments$109,303 $37,334 $146,637 $68,011 $6,818 $74,829 
Natural gas derivative instruments130,470 991 131,461 79,526 52 79,578 
Total assets$239,773 $38,325 $278,098 $147,537 $6,870 $154,407 
Liabilities:      
Electric derivative instruments$60,733 $36,559 $97,292 $35,854 $49,570 $85,424 
Natural gas derivative instruments22,509 1,210 23,719 16,678 2,172 18,850 
Total liabilities$83,242 $37,769 $121,011 $52,532 $51,742 $104,274 
24
Puget Energy andFair Value Fair Value
Puget Sound EnergyAt September 30, 2017 At December 31, 2016
(Dollars in Thousands)Level 2 Level 3 Total Level 2 Level 3 Total
Assets:           
Electric derivative instruments$7,106
 $4,550
 $11,656
 $30,666
 $5,794
 $36,460
Natural gas derivative instruments3,794
 4,032
 7,826
 23,316
 3,303
 26,619
Total assets$10,900
 $8,582
 $19,482
 $53,982
 $9,097
 $63,079
Liabilities: 
  
  
  
  
  
Interest rate derivative instruments1
$—
 $—
 $—
 $141
 $—
 $141
Electric derivative instruments36,482
 3,140
 39,622
 36,507
 4,822
 41,329
Natural gas derivative instruments23,998
 1,778
 25,776
 16,423
 2,678
 19,101
Total liabilities$60,480
 $4,918
 $65,398
 $53,071
 $7,500
 $60,571

_______________
1
Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

The following table presentstables 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 September 30,
(Dollars in Thousands)20222021
Level 3 Roll-Forward Net Asset/(Liability)ElectricNatural GasTotalElectricNatural GasTotal
Balance at beginning of period$5,916 $(717)$5,199 $(6,348)$(1,862)$(8,210)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1
6,939 — 6,939 20,510 — 20,510 
Included in regulatory assets / liabilities— (4)(4)— (6)(6)
Settlements(12,080)502 (11,578)(2,734)184 (2,550)
Transferred into Level 3— — — — — — 
Transferred out of Level 3— — — — — — 
Balance at end of period$775 $(219)$556 $11,428 $(1,684)$9,744 
Puget Energy and
Puget Sound Energy
Three Months Ended September 30,
(Dollars in Thousands)2017 2016
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period$643
 $1,456
 $2,099
 $(3,062) $(484) $(3,546)
Changes during period:           
Realized and unrealized energy derivatives:           
Included in earnings1
2,458
 —
 2,458
 574
 —
 574
Included in regulatory assets / liabilities—
 2,133
 2,133
 —
 (212) (212)
Settlements(1,783) (1,301) (3,084) 93
 84
 177
Transferred into Level 3(1,668) —
 (1,668) (727) —
 (727)
Transferred out of Level 31,760
 (34) 1,726
 2,532
 (331) 2,201
Balance at end of period$1,410
 $2,254
 $3,664
 $(590) $(943) $(1,533)

______________
1
Income Statement locations: Unrealized (gain) loss
Puget Energy and
Puget Sound Energy		Nine Months Ended September 30,
(Dollars in Thousands)20222021
Level 3 Roll-Forward Net Asset/(Liability)ElectricNatural GasTotalElectricNatural GasTotal
Balance at beginning of period$(42,752)$(2,120)$(44,872)$(23,718)$(1,135)$(24,853)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2
50,572 — 50,572 36,020 — 36,020 
Included in regulatory assets / liabilities— 481 481 — (1,055)(1,055)
Settlements(7,314)1,097 (6,217)(874)506 (368)
Transferred into Level 3— — — — — — 
Transferred out of Level 3269 323 592 — — — 
Balance at end of period$775 $(219)$556 $11,428 $(1,684)$9,744 
_______________
1 Income Statement locations: Unrealized gain (loss) on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.9 million for the three months ended September 30, 2017 and 2016.

The following table presents the Company's reconciliation of the changesreporting date for electric derivatives of $(8.8) million and $20.1 million for three months ended September 30, 2022 and 2021, 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 fair valuereporting date for electric derivatives of Level 3 derivatives in the fair value hierarchy:$31.2 million and $33.2 million for nine months ended September 30, 2022 and 2021, respectively.

Puget Energy and
Puget Sound Energy
Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period$972
 $625
 $1,597
 $(7,345) $(2,383) $(9,728)
Changes during period:           
Realized and unrealized energy derivatives:           
Included in earnings1
3,503
 —
 3,503
 3,228
 —
 3,228
Included in regulatory assets / liabilities—
 5,715
 5,715
 —
 2,869
 2,869
Settlements(5,622) (4,605) (10,227) (461) (1,731) (2,192)
Transferred into Level 3523
 (553) (30) (2,807) —
 (2,807)
Transferred out of Level 32,034
 1,072
 3,106
 6,795
 302
 7,097
Balance at end of period$1,410
 $2,254
 $3,664
 $(590) $(943) $(1,533)
______________
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 $1.9 millionand $4.0 million for the nine months ended September 30, 2017 and 2016, 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.
In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable, as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-Forward tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. The Company does periodically transact at locations or market price points that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for forward market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and gas commodity contracts, respectively, as of the reporting date.

25

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2017:
Puget Energy and
Puget Sound Energy		Fair Value     Range  
(Dollars in Thousands)
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Electric$4,550
 $3,140
 Discounted cash flow Power prices (per MWh) $8.54
 $28.98
 $17.99
Natural gas$4,032
 $1,778
 Discounted cash flow Natural gas prices (per MMBtu) $0.38
 $3.09
 $2.75
2022:
Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$37,334$36,559Discounted cash flowPower prices (per MWh)$37.81 $166.61 $89.96 
Natural gas$991$1,210Discounted cash flowNatural gas prices (per MMBtu)$4.48 $7.66 $5.32 
_______________
1
The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

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, 2016:2021:
Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$6,818 $49,570 Discounted cash flowPower prices (per MWh)$21.88 $119.38 $61.51 
Natural gas$52 $2,172 Discounted cash flowNatural gas prices (per MMBtu)$3.65 $7.54 $5.89 
___________
Puget Energy and
Puget Sound Energy		Fair Value     Range  
(Dollars in Thousands)
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Electric$5,794
 $4,822
 Discounted cash flow Power prices (per MWh) $11.86
 $33.52
 $27.61
Natural gas$3,303
 $2,678
 Discounted cash flow Natural gas prices (per MMBtu) $2.00
 $3.24
 $2.42
1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
_______________
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. At As of September 30, 20172022, and December 31, 2016,2021, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.7$31.7 million and $0.2$17.9 million, respectively.


Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of anyrecoverability whenever events or changes in circumstances indicate that wouldits carrying amount may not be more likely than not to reduce the fair value of the long-lived assets below their carrying value.recoverable. One such triggering event is a significant decrease in the forward market prices of power.
As of September 30, 2017,2022, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contractassets and determined that no impairment was determined to be impaired due toneeded. These intangible assets exist as a decreaseresult of the merger in forward prices for this contract of 3.5% from June 30, 2017, causing an impairment of $1.0 million. As of March 31, 2017, due to significant decreases2009, at which time the consolidated assets and liabilities were revalued in forward power prices of 14.1% for years 2017-2022, and 24.4% for years 2023-2035 from December 31, 2016, impairments totaling $80.3 million were recorded to the Company's intangible asset contracts.accordance with ASC 805.

The following table presents the impairments recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability:
26
Puget Energy 
(Dollars in Thousands)      
Valuation DateContract NameCarrying Value Fair Value Write Down
September 30, 2017Wells Hydro$10,621
 $9,609
 $1,012
       
March 31, 2017Wells Hydro$14,879
 $13,067
 $1,812
 Rocky Reach235,331
 159,818
 75,513
 Priest Rapids RP5,665
 2,657
 3,008
Total year-to-date impairments 
 
 $81,345


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. A less significant input is the discount rate reflective of PSE'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 DateUnobservable InputLow High Average
September 30, 2017      
Wells HydroPower prices (per MWh)$14.06 $26.86 $22.24
 Power contract costs per quarter (in thousands)4,126 4,126 4,126
       
March 31, 2017      
Wells HydroPower prices (per MWh)$8.76 $26.70 $20.86
 Power contract costs per quarter (in thousands)3,965 4,223 4,051
Rocky ReachPower prices (per MWh)$8.53 $48.21 $27.69
 Power contract costs per quarter (in thousands)5,827 6,780 6,150
Priest Rapids RPPower prices (per MWh)$13.70 $29.38 $23.14
 Power contract costs per year (in thousands)620 4,022 2,306
(6) Retirement Benefits



(5)Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portiona substantial majority of PSE employees. PensionFor employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. StartingEffective January 1, 2014, all non-represented and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees, along with International Brotherhood of Electrical Workers (IBEW)new UA represented employees hired on or after December 12, 2014 who elect to accumulate the Company contributionrehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula portion of the defined pension plan, willplan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible pay credits of 4% each year. They will also receive interest credits like other participants inyear into the cash balance pension formula of the defined benefit pension or 401k plan which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. account. PSE also maintainshas a non-qualified supplemental executive retirement planSupplemental Executive Retirement Plan (SERP) for itscertain key senior management employees.employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for the IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan.
In addition to providing pension benefits, PSE provides access tolegacy group medicalhealth care coverage and legacy life insurance benefits (Other Benefits)(Plan) for certain retired employees. These benefits are provided principally through an insurance company. The group medical insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020.
Puget Energy records purchase accounting adjustments associated with the re-measurementEnergy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income.

For further information, see Note 13, "Retirement Benefits" in the Combined Notes to Consolidated Financial Statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2021.

The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 20172022 and 2016:2021:
Puget EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended September 30,
(Dollars in Thousands)202220212022202120222021
Components of net periodic benefit cost:
Service cost$6,588 $6,722 $139 $115 $53 $34 
Interest cost6,066 5,595 313 293 70 72 
Expected return on plan assets(12,753)(12,060)— — (86)(84)
Amortization of prior service cost— (476)72 87 6 2 
Amortization of net loss (gain)1,595 2,951 618 588 (14)(10)
Net periodic benefit cost$1,496 $2,732 $1,142 $1,083 $29 $14 

27

Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits		Puget EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended September 30,Nine Months Ended September 30,
(Dollars in Thousands)2017 2016 2017 2016 2017 2016(Dollars in Thousands)202220212022202120222021
Components of net periodic benefit cost:           Components of net periodic benefit cost:
Service cost$5,020
 $4,976
 $228
 $271
 $18
 $21
Service cost$19,763 $20,166 $418 $344 $162 $117 
Interest cost7,093
 7,064
 571
 581
 125
 88
Interest cost18,197 16,786 939 879 233 226 
Expected return on plan assets(11,945) (11,589) —
 —
 (115) (112)Expected return on plan assets(38,260)(36,179)— — (284)(266)
Amortization of prior service cost(495) (495) 11
 11
 —
 —
Amortization of prior service cost— (1,428)218 262 17 5 
Amortization of net loss (gain)—
 —
 269
 228
 (101) (233)Amortization of net loss (gain)4,786 8,852 1,853 1,763 (22)(30)
Net periodic benefit cost$(327) $(44) $1,079
 $1,091
 $(73) $(236)Net periodic benefit cost$4,486 $8,197 $3,428 $3,248 $106 $52 


Puget Sound EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended September 30,
(Dollars in Thousands)202220212022202120222021
Components of net periodic benefit cost:
Service cost$6,588 $6,722 $139 $115 $53 $34 
Interest cost6,066 5,595 313 293 70 72 
Expected return on plan assets(12,754)(12,061)— — (86)(84)
Amortization of prior service cost— (378)72 87 6 2 
Amortization of net loss (gain)3,770 5,465 662 635 (15)(11)
Net periodic benefit cost$3,670 $5,343 $1,186 $1,130 $28 $13 

Puget Sound EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Nine Months Ended September 30,
(Dollars in Thousands)202220212022202120222021
Components of net periodic benefit cost:
Service cost$19,763 $20,166 $418 $344 $162 $117 
Interest cost18,197 16,786 939 879 233 226 
Expected return on plan assets(38,262)(36,182)— — (284)(266)
Amortization of prior service cost— (1,135)218 262 17 5 
Amortization of net loss (gain)11,310 16,396 1,986 1,906 (26)(40)
Net periodic benefit cost$11,008 $16,031 $3,561 $3,391 $102 $42 
28
Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
 Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 2017 2016 2017 2016
Components of net periodic benefit cost:           
Service cost$15,060
 $14,185
 $685
 $814
 $54
 $70
Interest cost21,279
 21,516
 1,714
 1,744
 375
 399
Expected return on plan assets(35,837) (34,964) —
 —
 (346) (334)
Amortization of prior service cost(1,485) (1,485) 33
 32
 —
 —
Amortization of net loss (gain)—
 —
 807
 683
 (302) (289)
Net periodic benefit cost$(983) $(748) $3,239
 $3,273
 $(219) $(154)


 Puget Sound Energy
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
 
  Three Months Ended September 30,
 (Dollars in Thousands)2017 2016 2017 2016 2017 2016
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$5,020
 $4,976
 $228
 $271
 $18
 $21
 Interest cost7,093
 7,064
 571
 581
 125
 88
 Expected return on plan assets(11,965) (11,638) —
 —
 (115) (112)
 Amortization of prior service cost(393) (393) 11
 11
 —
 —
 Amortization of net loss (gain)3,262
 3,963
 392
 333
 (160) (295)
 Net periodic benefit cost$3,017
 $3,972
 $1,202
 $1,196
 $(132) $(298)


 Puget Sound EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
 
  Nine Months Ended
September 30,
 (Dollars in Thousands)2017 2016 2017 2016 2017 2016
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$15,060
 $14,185
 $685
 $814
 $54
 $70
 Interest cost21,279
 21,516
 1,714
 1,744
 375
 399
 Expected return on plan assets(35,896) (35,110) —
 —
 (346) (334)
 Amortization of prior service cost(1,180) (1,180) 33
 33
 —
 —
 Amortization of net loss (gain)9,786
 11,443
 1,175
 997
 (480) (474)
 Net periodic benefit cost$9,049
 $10,854
 $3,607
 $3,588
 $(397) $(339)

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 20172022 and December 31, 2016:2021:
Puget Energy and
Puget Sound Energy		Qualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Nine Months EndedYear EndedNine Months EndedYear EndedNine Months EndedYear Ended
(Dollars in Thousands)September 30,
2022		December 31,
2021		September 30,
2022		December 31,
2021		September 30,
2022		December 31,
2021
Change in benefit obligation:
Benefit obligation at beginning of period$834,960$849,383$43,155$46,742$11,654$12,114
Amendments—————205
Service cost19,76326,888418456162155
Interest cost18,19722,3819391,183233302
Actuarial loss (gain)(1,439)(6,826)—828(241)(514)
Benefits paid(37,424)(55,831)(1,485)(6,054)(856)(803)
Medicare part D subsidy received—————195
Administrative Expense—(1,035)————
Benefit obligation at end of period$834,057$834,960$43,027$43,155$10,952$11,654
Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
 Nine Months Ended
 Year
Ended		 Nine Months Ended
 Year
Ended		 Nine Months Ended
 Year
Ended
(Dollars in Thousands)September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016
Change in benefit obligation:           
Benefit obligation at beginning of period$652,607
 $643,088
 $51,734
 $51,279
 $11,194
 $13,946
Service cost15,060
 18,913
 685
 1,085
 54
 93
Interest cost21,279
 28,689
 1,714
 2,325
 375
 533
Actuarial loss (gain)(253) 1,545
 —
 106
 373
 (2,262)
Benefits paid(31,344) (38,730) (1,428) (3,061) (857) (1,264)
Medicare part D subsidy received—
 —
 —
 —
 100
 148
Administrative Expense—
 (898) —
 —
 —
 —
Benefit obligation at end of period$657,349
 $652,607
 $52,705
 $51,734
 $11,239
 $11,194


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, 20172022, are expected to be at least $18.0 million, $1.9$2.8 million and $0.3 million, respectively. During the three months ended September 30, 2017, the Company made no contributions to fund the qualified pension plan, as the aggregate funding for the year has already been reached for the year ending December 31, 2017. During the three months ended September 30, 2017, the Company contributed $0.5 million and $0.1 million to fund the SERP and other postretirement plan, respectively. During the nine months ended September 30, 2017, theThe Company contributed $18.0 million $1.4 million and $0.2$1.5 million to fund the qualified pension plan and the SERP during nine months ended September 30, 2022 and 2021. The Company contributed an immaterial amount to fund the other postretirement plan, respectively.plans.


(6)
(7) Regulation and Rates


2013 ExpeditedGeneral Rate Filing, Decoupling and Centralia DecisionCase
On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the expedited rate filing (ERF) and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No.7 in the ERF/decoupling proceeding approved PSE's ERF filing withPSE filed a small change to its cost of capital to 7.77% which updated long-term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. This

order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the K-Factor (rate plan) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next general rate case (GRC) which was filed January 13, 2017, as discussed below. In theincludes a three year multiyear rate plan increases are subject towith the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a capreturn on equity of 3.0%9.9% in all three-rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requested recovery of forecasted plant additions through 2022 as required by Revised Code of Washington 80.28.425 as well as forecasted plant additions through 2025, the final year of the total revenue for customers.multiyear rate plan. The Washington Commission issued a procedural schedule and the case is pending. In August 2022, three separate partial multiparty settlement agreements were reached. For further details regarding the partial settlement agreements, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report. The Company cannot predict the outcome of the case at this time.

General Rate Case Filing
On January 13, 2017, PSE filed itsa GRC with the Washington Commission which proposedon June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.74%,7.39% or 6.69%6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%9.4%. The requestedorder also resulted in a combined electric tariff changes were a net increase to electric of $86.3$29.5 million, or 4.1%1.6%, annually. The requested combinedand to natural gas tariff changes were a net decrease of $22.3$36.5 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.
PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by4.0%. However, the Washington Commission would resolve all but fourextended the amortization of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.6% or 6.55% after-tax,certain regulatory assets, PSE’s electric decoupling deferral, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.

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 are expectedPGA deferral to mitigate the impact of weatherthe rate increase in response to the economic instability created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.1%, and the natural gas increase to $1.3 million, or 0.2%, and became effective October 15, 2020 and October 1, 2020, respectively.
29

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

Power Cost Only Rate Case
On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).
On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to recordinclude in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a monthly adjustmentpower cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to itsthe update on power costs with rates effective July 1, 2021.

Decoupling Filings
On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and natural gas operating revenues relatedfixed power cost sections originally filed through the annual May 2020 decoupling filing. The extension requires PSE to move amortization balances for electric transmission and distribution, natural gas operations and general administrative costsdecoupling as of August 31, 2020 to be collected from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. Asfor a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are parttwo-year period, instead of the PCA and PGA mechanisms, are not included in the decoupling mechanism. PSE has requested thatoriginally approved one-year period. Additionally, through approving the electric energy supply fixed costs becost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups.
On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included ina true up of the decoupling mechanism in its pending GRC as is discussed above.
Underover-collection amounts for the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing partyperiod of October 15, 2020 through December 31, 2020 in PSE’s pending GRC is advocating that PSE'sannual May 2021 decoupling mechanism be changed so thatfiling.
On June 1, 2021, the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE's existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms. PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. PSE's decoupling mechanism over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.

The Washington Commission approved the followingmulti-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021.
On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021.
On September 30, 2022, PSE requestsperformed an analysis to change rates under itsdetermine if 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, 20172.0% $41.9
May 1, 20161.0 20.8
Natural Gas:   
May 1, 20172.4% $22.4
May 1, 20162.8 25.4
_______________
1
The increase in revenue is net of reductions from excess earnings of $11.9 millionrevenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.

As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows for natural gas with no impacts to electric:
Effective Date Accrued Through
Deferrals not Included in Annual Rate Increases
(Dollars in Millions)
Natural Gas: 
2016$47.4
201528.7

Existing deferrals maydeferred revenue will be included in customer rates beginning in May 2018, subject to subsequent applicationcollected within 24 months of the earnings test and the 3.0% cap onannual period; therefore, no reserve adjustment was booked to 2022 electric or natural gas decoupling related rate increases.  

Electric Regulation and Rates
Storm Damage Deferral Accounting
The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for a system average interruption duration index. For the nine months endedrevenue. At September 30, 2017 and 2016, PSE incurred $21.12021, the analysis estimated $2.0 million and $15.6 million, respectively,of electric deferred revenue not to be collected within 24 months of the annual period in storm-related2021; therefore, a reserve adjustment was booked to 2021 electric transmission and distribution system restoration costs,decoupling revenue. At September 30, 2021, natural gas deferred revenue was estimated to be collected within 24 months of which $12.4 millionthe annual period in 2021; therefore, no reserve adjustment was deferredbooked to a regulatory asset in 2017 and $6.5 million in 2016.2021 natural gas decoupling revenue.

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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.

The graduated scale that was applicable through December 31, 2016 was as follows:
Annual Power Cost VariabilityCompany’s Share Customers' Share
+/- $20 million100% —%
+/- $20 million - $40 million50 50
+/- $40 million - $120 million10 90
+/- $120 + million5 95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effectEffective January 1, 2017, and applies the following graduated scale:
 Company's Share Customers' Share
Annual Power Cost VariabilityOver Under Over Under
Over or Under Collected by up to $17 million100% 100% —% —%
Over or Under Collected by between $17 million - $40 million35 50 65 50
Over or Under Collected beyond $40 + million10 10 90 90

The settlement also resultedscale is used in the following changes to the PCA mechanism:

Company’s ShareCustomers' Share
Annual Power Cost VariabilityOverUnderOverUnder
Over or Under Collected by up to $17 million100 %100 %— %— %
Over or Under Collected by between $17 million - $40 million35 50 

65 50 
Over or Under Collected beyond $40 + million10 10 

90 90 
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.


For the nine months ended September 30, 2017,2022, in its PCA mechanism, PSE under recovered its powerallowable costs by $8.9$12.5 million of which no amountzero was apportioned to customers.customers and $1.0 million of interest was accrued on the deferred customer balance. This compares to an overunder recovery of powerallowable costs of $1.4$49.7 million for the nine months ended September 30, 20162021, of which no amounts were$20.3 million was apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease incustomers and accrued $1.2 million of interest on the total baseline rate and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.customer balance.


Electric Conservation RiderPower Cost Adjustment Clause Filing
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 load being different than the forecasted load set in rates.

The following table sets forth conservation rider rate adjustments approved byOn July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Special Contracts, which will be included in allowed rates under the corresponding expected annual impact on PSE’s revenue based onDecoupling Schedule 142 effective October 15, 2020.
PSE exceeded the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 20170.7% $16.5
May 1, 2016(0.5) (11.7)

Electric Property Tax Tracker Mechanism
$20.0 million cumulative deferral balance in its PCA mechanism in 2020. The purposesurcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $76.1 million. Under the terms of the property tax trackerPCA’s sharing mechanism isfor under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to pass throughrecover the cost of all property taxes incurred by the Company. The mechanism removes property taxes from general ratesdeferred balance in Docket UE-210300, and includes 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 paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes and true-ups to the rate from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission allowed the recovery effective December 1, 2021.
Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the 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, 2017(0.04)% $(0.9)
May 1, 20160.3 5.7

Federal Incentive Tracker Tariff
The federal incentive tracker tariff passes through to customers the benefits associatedremaining $36.7 million, or $38.4 million including interest. On April 29, 2022, PSE filed a 2021 PCA report with realized treasury grants and production tax credits. 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.
The following table sets forth the federal incentive tracker tariff revenue requirement proposed, as originally filed, by PSE and/or approved by the Washington Commission that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and the corresponding expected annual impact on PSE’s revenue based on the effective dates:allowing recovery from January 1, 2023 through November 30, 2023.

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, 2018, proposed0.2% $(48.2)
January 1, 20170.3 (51.7)
January 1, 2016(0.2) (57.3)
Purchased Gas Adjustment Mechanism

Residential Exchange Benefit
The residential exchange program passes through the residential exchange program benefits that PSE will be receiving from the Bonneville Power Administration (BPA) betweenOn October 1, 2017 and September 30, 2019.  Rates change bi-annually on October 1.

The following table sets forth residential exchange benefit adjustments approved by28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the corresponding expectedtracker rates under Schedule 106, decrease annual impact on PSE’s revenue basedby $21.5 million. Those annual 2021 PGA rate increases will be set in addition to continuing the collection 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 1, 2017(0.6)% $(80.8)
October 1, 20152.4 (76.4)

Power Cost Update Compliance Filing
The power cost update compliance filing is an update to a limited-scope proceeding to periodically reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely reviewremaining balance of new resource acquisition costs and inclusion of such costs$69.4 million under Supplemental Schedule 106B, which were set, in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. Oneffect, through September 30, 2016,2023 per the 2019 GRC.
On October 21, 2022, PSE filed with the Washington Commission to change PGA rates effective November 1, 2022. As part of that filing, PSE requested an update to power costsannual revenue increase of $155.3 million; where PGA rates, under Schedule 95, which was consistent with101, increase annual revenue by $142.1 million, and the Washington Commission’s Order No. 04 in the 2014 PCORC, and requiredtracker rates under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC.Schedule 106, increase annual revenue by $13.2 million.

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The following table sets forthpresents the updated compliance filing rate adjustment that became effective onPGA mechanism balances and activity at September 30, 2022 and December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date:31, 2021:
 
Puget Sound Energy
(Dollars in Thousands)At September 30,At December 31,
PGA receivable balance and activity20222021
PGA receivable beginning balance$57,935 $87,655 
Actual natural gas costs295,795 364,775 
Allowed PGA recovery(305,458)(396,236)
Interest1,154 1,741 
PGA receivable ending balance$49,426 $57,935 

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
December 1, 2016(1.7)% $(37.3)
Get to Zero Depreciation Deferral

Natural Gas Regulation and 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 versus forecast conservation expenditures from the prior year as well as actual load being different than 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, 2017(0.1)% $(1.0)
 May 1, 20160.3 2.9

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 removes property taxes from general rates and includes those costs for recovery inOn April 10, 2019, PSE filed an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes.

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 DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2017(0.1)% $(1.1)
May 1, 20160.4 3.5

Natural Gas Cost Recovery Mechanism
The purpose of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on fileaccounting 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 intended effectGTZ projects with lives of enhancing10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the safetypetition request. At September 30, 2022 and December 31, 2021, PSE deferred $10.5 million and $6.6 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89%. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original GRC filing. The ruling also allows continued deferral of the natural gas distribution system.depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's then-next GRC, which PSE filed on January 31, 2022, and is currently pending. Finally, the final order set the rate at which PSE could defer and recover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the Federal Energy Regulatory Commission (FERC).
The following table sets forth CRM rate adjustments approved by
Crisis Affected Customer Assistance Program
On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective electric and natural gas service tariffs. The purpose of this filing was to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP-1) (Dockets UE-200331 and UG-200332), to mitigate the corresponding expected annualeconomic impact of the COVID-19 pandemic on PSE’s revenue based on the effective dates:customers. CACAP-1 would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to September 30, 2020.
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20170.5% $4.9
November 1, 20160.6 5.6

Purchased Gas Adjustment
PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, 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 byOn March 28, 2021, the Washington Commission to accrue carrying costs on PGA receivableapproved PSE’s CACAP-2 (Dockets UE-210137 and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively,UG-210138). With a program budget of $20.0 million for electric customers and $7.7 million for natural gas cost through the PGA mechanism.customers, CACAP-2, which ran from April 12, 2021, to March 29, 2022, provided up to $2,500 in bill assistance in arrearages per year for each qualifying low-income household.
The following table sets forth the PGA rate adjustments approved byOn October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP(Dockets UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission andapproved the corresponding expected annual impactSupplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s revenue based on the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2017(3.3)% $(30.8)
November 1, 2016(0.4) (4.1)

(7)Asset Retirement Obligations

The Company has recorded liabilitiesSchedule 129 Home Energy Lifeline Program (HELP), with a combined total budget of $34.5 million for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles,both electric and natural gas mains where disposal is governed by ASC 410 “Asset Retirementresidential customers (capped at $23.7 million and Environmental Obligations" (ARO)$10.8 million, respectively). Supplemental CACAP benefits offered to cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an opt-out option, in December 2021.
On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments.
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Storm Loss Deferral Mechanism
The CCR ruleWashington Commission has defined deferrable weather-related events and two new agreements which include a consent decree withprovided that costs in excess of the Sierra Clubannual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations. The

changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.
On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional costs, such as, monitoring, water treatment, forced evaporation and post-closure careElectronics Engineers outage criteria for all Colstrip Units. As a result, in 2016 the Company increased the Colstrip ARO ending liability by $45.7 million for Colstrip Units 1 and 2 and $37.0 million for Colstrip Units 3 and 4.
The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. The Company will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.
system average interruption duration index. For the nine months ended September 30, 2017 the Company reviewed the estimated remediation2022, PSE incurred $6.8 million in weather-related electric transmission and distribution system restoration costs, at Colstripof which $0.2 million was deferred as regulatory assets related to storms that occurred in 2021. This compares to $29.0 million incurred in weather-related electric transmission and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $1.5 million for PSE and $1.4 million for Puget LNG in September 2017.
The following table describes the changes to the Company’s AROdistribution system restoration costs for the nine months ended September 30, 2017:2021, of which the Company deferred $19.0 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.


(8) Commitments and Contingencies
Puget Energy and
Puget Sound Energy

 
  
(Dollars in Thousands)Changes in ARO
Balance at December 31, 2016$200,345
New asset retirement obligation recognized in the period1
2,881
Liability adjustments(1,035)
Revisions in estimated cash flows(18,462)
Accretion expense4,126
Balance at September 30, 2017$187,855
_______________
1
New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.


(8)Commitment and Contingencies


Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. On March 6, 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, Districteach of Montana. On July 12, 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 on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. Due to a re-estimate of Colstrip Units 1 and 2 ARO costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected bycoal-fired generating units located in Colstrip, Montana. PSE has accelerated the settlement, and allegations in the lawsuit againstdepreciation of Colstrip Units 3 and 4 were dismissedto December 31, 2025 as part of the settlement. While2019 GRC. The 2017 GRC 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 September 2, 2022, PSE has estimatedand Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the AROapplicable held for sale accounting criteria were not met as of September 30, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of September 30, 2022.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood
On March 9, 2016,May 19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a natural gas explosion occurredlawsuit against the Montana Attorney General challenging the constitutionality of Montana Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. On September 29, 2022, the magistrate judge in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filedDistrict Court proceeding issued a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March

28, 2017, pipeline safety regulators and PSE reached a settlement in responserecommendation to the complaint. As partpresiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. On October 18, 2022, the agreement, PSE agreed to payU.S. District Court Judge accepted in full the magistrate judge recommendation for a penaltypermanent injunction against enforcement of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million, of which $1.3 million was suspended. On June 30, 2017, PSE paid the $1.5 million penalty it had accrued previously to a liability reserve account for property damage claims. However, litigation is still pending regarding damage and personal injury claims.Senate Bill 266.


Other Commitments and Contingencies
The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company recorded reserves of $0.6 million and $0.7 million relating to these claims as of September 30, 2017 and December 31, 2016, respectively.
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, 2016,2021, during the nine months ended September 30, 2017,2022, the Company entered into new power supplyElectric Portfolio and serviceElectric Wholesale Market Transaction contracts with estimated payment obligations totaling $729.5$466.6 million through 2028.2031.

For further information, see Part II, Item 8, Note 16, "Commitments and Contingencies" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.


(9)  Leases

As of September 30, 2022, there have been no material changes regarding the Company's leases. For further information, see Part II, Item 8, Note 9, "Leases" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.


33

(10) Other

Long-Term Debt
On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.
On June 23, 2021, Puget Energy received an equity contribution from Puget Equico, LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan.
On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15of each year. The proceeds from the issuance were used for repayment of commercial paper as well as general corporate purposes.
On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay Puget Energy's $450.0 million 5.625% notes that were originally scheduled to mature July 2022.
On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.

Short-Term Debt
As of September 30, 2022, $102.0 million was outstanding under the commercial paper program at PSE. For further information, see Part II, Item 8, Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.

Credit Facilities
On May 16, 2022, Puget Energy entered into an $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the Secured Overnight Funding Rate (SOFR), as the LIBOR is being discontinued in 2023. The proceeds of the PE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. As of September 30, 2022, $93.3 million was drawn and outstanding under the facility, of which $34.3 million was classified as long-term debt and $59.0 million was classified as short-term debt.
On May 16, 2022, PSE entered into an $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR is being discontinued in 2023. The proceeds of the PSE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. As of September 30, 2022, no amount was drawn under PSE's credit facility.
On September 26, 2022, PE borrowed $50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds will be used for general corporate purposes.
For further information, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.
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Item 2.     Management's Discussion and Analysis of Financial Condition and Results of Operations


The following discussion and analysis is intended to promote understanding of the results of operations and financial condition, is provided as a supplement to, and should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. This section generally discusses the results of operations and changes in financial condition for period ended September 30, 2022 compared to 2021.For discussion related to the results of operations and changes in financial condition for period ended September 30, 2021 compared to 2020 refer to Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our period ended September 30, 2021, Form 10-Q, which was filed with the United States Securities and Exchange commission (SEC).The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2016.2021. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.operations, including the Coronavirus disease 2019 (COVID-19) pandemic.




Overview


Puget Energy is an energy services holding company and substantially all of its operations are conducted through its wholly-owned subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction.liquefied natural gas (LNG) facility. 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 Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation and(BCIMC), the Alberta Investment Management Corporation.Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V., Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. Puget Energy and PSE are collectively referred to herein as “the Company.”
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.


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COVID-19 Update
The outbreak of COVID-19 has resulted in a global pandemic. The Company continues to monitor the impact of the pandemic and take steps to mitigate known risks. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions to customers.
Due to business disruptions caused by the COVID-19 pandemic, the Company incurred increased costs and partially offset cost savings. On September 3, 2020, the Company filed an accounting petition with the Washington Commission, requesting authorization to defer the costs and foregone revenue net of offsets associated with the COVID-19 public health emergency. On November 6, 2020, PSE filed a revised petition which was approved on December 10, 2020 by the Washington Commission granting PSE's accounting petition in part by allowing the deferral of COVID-19 incremental costs and foregone revenue net of offsets. As of September 30, 2022, PSE deferred $28.1 million specific to COVID-19 net of offsets.
On March 27, 2020, the U.S. Government enacted the CARES Act, which provided approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 pandemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. Among other provisions, the CARES Act includes modifications to corporate income tax provisions, including temporary suspension of certain payment requirements for the employer portion of social security taxes. As a result of these modifications, the Company deferred payroll taxes totaling $6.8 million as of September 30, 2022.
Further detail regarding the factors and trends affecting performance of the Company during the nine months ended September 30, 2022, is set forth below in this "Overview" section as well as in other sections of Management's Discussion and Analysis.

Factors and Trends Affecting PSE's Performance
PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in 2022 and will continue to do so in future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process.  The principal business, economic and other factors that affect PSE'sPSE’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;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;
Bonus depreciation•Failure to complete capital projects on schedule and within budget or the impactabandonment 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;base and customer rates;
•General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; and
•Federal, state, and local taxes.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;
Further detail regarding•The effectiveness of PSE’s risk management policies and procedures;
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•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the factorsCompany’s generation and trends affecting performancetransmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
•Acts of war or terrorism locally or abroad, or the Company duringimpact of civil unrest to infrastructure or preventing access to infrastructure and its impact on the fiscal quarter ended September 30, 2017 is set forth below in this "Overview" section as well as in other sectionssupply chain and prices of Management's Discussiongoods and Analysis.services; and

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

Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 20172022 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable 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 Utilities and Transportation Commission (Washington Commission).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. Accordingly,Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief onthrough a regular and frequent basis inrate case with the foreseeable future. In addition, theWashington Commission. The Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

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

General Rate Case Filing
On January 13, 2017, PSE filed itsa general rate case (GRC) which includes a three year multiyear rate plan with the Washington Commission which proposedon January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three-rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requested recovery of forecasted plant additions through 2022 as required by Revised Code of Washington 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. The Washington Commission issued a procedural schedule and the case is pending. The Company cannot predict the outcome of the case at this time.
In August 2022, three separate partial multiparty settlement agreements were reached. On August 5, 2022, parties filed an unopposed partial multiparty settlement agreement relating to the Voluntary Long Term Renewable Energy Purchase rider, known as Green Direct, resolving the method for calculating the energy credit Green Direct customers receive, among other matters. On August 26, 2022, six of the sixteen parties, including PSE, filed a partial multiparty settlement agreement with the Washington Commission determining that the regulated portion of the Tacoma LNG Facility will be included in rates, as a tracker, beginning November 2023. Also, on August 26, 2022, twelve of the sixteen parties, including PSE, filed a partial multiparty settlement agreement with the Washington Commission for the remaining items in the GRC (GRC settlement). The GRC settlement agreement sets a two year rate plan instead of a three year plan as originally filed, provides a capital structure of 49.0% equity and 51.0% debt, and a return on equity of 9.4% with an overall rate of return of 7.16%. The settlement also provides a combined electric tariff change that would result in a base revenue increase of $223.5 million in year one, and of $38.5 million in year two, or 9.7% and 1.6%. The settlement also provides a combined natural gas tariff change that would result in a base increase of $70.8 million in year one and $19.5 million in year two, or 6.4% and 1.7%. The final outcome is still pending.
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PSE filed a GRC with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.74%,7.39% or 6.69%6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%9.4%. The requestedorder also resulted in a combined electric tariff changes were a net increase to electric of $86.3$29.5 million, or 4.1%1.6%, annually. The requested combinedand to natural gas tariff changes were a net decrease of $22.3$36.5 million, or 2.4%, annually. The filing was subsequently suspended, which means that4.0%. However, the final rates grantedWashington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s purchased gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the proceeding will go into effect no later than December 13, 2017.economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.1% and the natural gas increase to $1.3 million, or 0.2% and became effective October 15, 2020 and October 1, 2020, respectively.
On August 6, 2020, PSE filed a supplemental filingpetition for judicial review with the Superior Court of the State of Washington for King County challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the GRC on April 3, 2017, which among other things provided updatesInternal Revenue Service (IRS) normalization and consistency rules.
PSE requested a Private Letter Ruling (PLR) from the IRS regarding this matter. On October 7, 2020, PSE, the Washington Commission and interveners agreed to power costs.dismiss the petition for judicial review. The requested combined electric tariff changesagreement was based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.
PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. It also requested that electric energy supply

fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an Expedited Rate Filing (ERF) that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement withcommitment from the Washington Commission. The settlement agreement,Commission that if accepted bythe IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission would resolve all but fouropen a proceeding to review and enact the changes required by the IRS ruling. There was approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE requested it be allowed to track and recover.
On July 30, 2021, the IRS issued a PLR to PSE which concluded that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. On September 28, 2021, the Washington Commission issued an order amending its order previously issued on July 8, 2020 to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed in the PLR. To reflect the impact of the contested issues betweenPLR, PSE recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021. The annualized overall rate impact for this element was an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to an overall annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the settling parties.$59.6 million granted in the revised final order. The order also led to an overall annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%.

Power Cost Only Rate Case
A power cost only rate case (PCORC) is a limited-scope proceeding to reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission is not required to but historically has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.
On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).
On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement agreement provides forresulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a weightedpower cost of capital of 7.60% or 6.55% after-tax, andupdate through a capital structure of 48.5% in common equitycompliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a return on equity of 9.5%. The settlement also recommends a combined electric tariff change that would result in a netrevenue increase of $20.2$70.9 million or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM,3.3% due to the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were heldupdate on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.power costs with rates effective July 1, 2021.


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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 are expected to mitigateassist in mitigating the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs and fixed production costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will beare recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the power cost adjustment (PCA) and purchased gas adjustment (PGA)PGA mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above.
Under the current mechanism, theThe revenue recorded under the decoupling mechanisms iswill be affected by customer growth and not actual consumption. One opposing Party in PSE’s pending GRC is advocating that PSE’s decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is setconsumption except for fixed production costs, which are held at the numberlevel of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE’s existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excludedcost from the decoupling mechanisms.
most recent rate proceeding and are not impacted by customer growth. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. The decoupling mechanism over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.April time period.
On April 28, 2017,December 23, 2020, the Washington Commission approved PSE's requestPSE’s filing to changeupdate Schedule 142 decoupling amortization rates, under its electric and natural gaswith an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling mechanism, effective Mayfiling.
On June 1, 2017. The overall changes represent a rate increase for electric customers of $41.9 million, or 2.0%, annually, and a rate increase for natural gas customers of $22.4 million, or 2.4%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2016. As a result, PSE filed with2021, the Washington Commission approved a reductionmulti-party settlement agreement in electric decoupling deferral and revenuePSE's PCORC that was originally filed on December 9, 2020. As part of $11.9 million and a reduction in natural gas decoupling deferral and revenue of $2.2 million. This was included as a reduction tothis settlement agreement, the electric and natural gas rate increases noted above. As noted earlier, the Company is also limitedannual fixed power cost allowed revenue was updated to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not includedreflect changes in the 2017 rate increase is $47.4 million for naturalapproved revenue requirement. The changes took effect on July 1, 2021.
On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue that was accrued through December 31, 2016.updated to reflect changes in the approved revenue requirement. The amount not recovered in 2017 may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% capchanges took effect on decoupling related rate increases.  October 1, 2021.
Due to the 3.0% cap on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet,On September 30, 2022, PSE performed an analysis as of September 30, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period.period, per ASC 980.  If not, for U.S. Generally Accepted Accounting Principles (GAAP) purposes only, PSE would need to record a reserve against the decoupling revenue and corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated all current deferred revenues forthat electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2022 electric or natural gas decoupling revenue. At September 30, 2021, the analysis estimated $2.0 million of electric deferred revenue not to be collected within 24 months of the annual period in 2021; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. Whereas, at September 30, 2021, natural gas deferred revenue was estimated to be collected within 24 months of the annual period in 2021; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue.
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The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Electric:
May 1, 20222
(1.0)%$(23.5)
May 1, 20213
1.021.4
January 1, 2021(1.0)(20.6)
October 15, 20204
(0.5)(10.2)
May 1, 20200.22.0
Natural Gas:
May 1, 2022(0.7)%$(7.4)
May 1, 20211.515.0
May 1, 2020(0.5)(4.8)
__________________
1 For electric and natural gas rates effective May 1, 2022, May 1, 2021 and May 1, 2020, there were no adjustmentsexcess earnings that impacted the approved revenue change.
2 For the electric rates effective May 1, 2022, there was $8.0 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2023 due to 2017 decouplingthe 3% rate cap.
3 For the electric rates effective May 1, 2021, there was $24.1 million of excess deferred revenues other thanfor delivery and fixed power costs which could not be set in rates until May 1, 2022 due to record the previously unrecognized decoupling deferrals of $20.8 million.3% rate cap.
Other Proceedings
Microsoft
On October 7, 2016, PSE filed a tariff to provide open access service4 The 2019 GRC final order lengthened the recovery period from the original one-year recovery to a narrow settwo-year recovery of qualifying customers. Subsequent to that tariff filing, parties to the case reached an all-party settlement that would convert the tariff to a special contract only allowing retail accessApril 2022. The remaining decoupling amortization balances for the loads of the Microsoft Corporation currently being served under PSE’s electric Schedule 40. The special

contract includes the following conditions: (i) Microsoft exceed Washington State’s current renewable portfolio standards, (ii) the remainder of theirdelivery and fixed power be carbon free, (iii) there be no reduction in their funding of PSE’s conservation programs, (iv) an exit fee be paid that will be a straight pass through to customers and (v) Microsoft fund enhanced low-income support. A definitive agreement among the parties, the special contract and supportive testimony were filed with the Washington Commission on April 11, 2017 with hearings that occurred on May 3, 2017. The Washington Commission issued an order on July 13, 2017 approving PSE’s special contract with Microsoft. Microsoft cannot begin taking service under the special contract until it has the required metering installed and has contracts for the supply and transmission of its power supply. PSE currently anticipates these conditions will be met in late 2018.

Voluntary Long-Term Renewable Energy
On September 28, 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product, effective September 30, 2016. This provides customers with energy choices 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 initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh) and government customers. Approximately 135 MW of new wind generation facilities will be constructed$1.7 million were included in the region by a developer under contract to PSE which will meet the demand for this voluntary renewable energy product project.electric decoupling mechanism tariff rates, effective May 1, 2022.



Electric Rates
Power Cost Adjustment Mechanism
PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
The graduated scale that was applicable through December 31, 2016 was as follows:
Annual Power Cost VariabilityCompany's Share Customers’ Share
+/- $20 million100% —%
+/- $20 million - $40 million50 50
+/- $40 million - $120 million10 90
+/- $120 + million5 95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effectEffective January 1, 2017, and applies the following scale:
 Company's Share Customers’ Share
Annual Power Cost VariabilityOver Under Over Under
Over or Under Collected by up to $17 million100% 100% —% —%
Over or Under Collected by between $17 million - $40 million35 50 65 50
Over or Under Collected beyond $40 + million10 10 90 90

The settlement also resultedgraduated scale is used in the following changes to the PCA mechanism:
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
Company's ShareCustomers’ Share
Annual Power Cost VariabilityOverUnderOverUnder
Over or Under Collected by up to $17 million100%100%—%—%
Over or Under Collected by between $17 million - $40 million35506550
Over or Under Collected beyond $40 + million10109090
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);

Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.

On September 30, 2016, PSE filed an accounting petition with the Washington Commission which requests 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 deferral period requested is January 1, 2017 through December 31, 2017 when rates go into effect from PSE's 2017 GRC.  On November 10, 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition.
For the nine months ended September 30, 2017,2022, in its PCA mechanism, PSE under recovered its powerallowable costs by $8.9$12.5 million of which no amountzero was apportioned to customers.customers and $1.0 million of interest was accrued on the deferred customer balance. This compares to an overunder recovery of powerallowable costs of $1.4$49.7 million for the nine months ended September 30, 20162021, of which no amounts were$20.3 million was apportioned to customers. Although load increased in 2017 compared to 2016 that increasecustomers and $1.2 million of interest was offset by a decreaseaccrued on the total deferred customer balance.
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Power Cost Adjustment Clause Filing
PSE updated its Schedule 95 rates in the total baseline rate and an increase in costs. Additionally,Power Cost Adjustment Clause tariff to reflect the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portiontransition fee as required by Section 12 of the Special Contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation resulting from a Special Contract customer becoming a transportation customer as well as small variable power cost adjustments.
PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline rate.  The fixedpower costs, will become partthereby creating an under-recovery of $76.1 million. Under the terms of the decouplingPCA’s sharing mechanism assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed productionfor under-recovered power costs, are being deferred using the fixed cost portionPSE absorbed $32.1 million of the baseline rate.

Electric Conservation Rider
On April 28, 2017,under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021.
Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On April 29, 2022, PSE filed a 2021 PCA report with the Washington Commission that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023.
The following table sets forth power cost adjustment clause filing approved PSE's requestby the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase
(Decrease)
in Revenue
(Dollars in Millions)
December 1, 20201
2.1%$43.9
October 15, 2020(0.2)(3.3)
July 3, 20202
1.223.9
______________
1 The Schedule 95 PCA mechanism rates from the prior year that recover the 2019 imbalance (effective December 1, 2020) have been extending through December 31, 2022 to changerecover the imbalance attributable to 2020. PSE filed the PCA imbalance rate extension with the Washington Commission to recover PCA imbalance attributable to 2021 from January 1, 2023 to November 30, 2023.
2 The rates under itsfor the Electric Special Contract were zeroed out effective July 3, 2020 following the July 2019 through June 2020 period. The actual residual amount resulting at July 31, 2020 were included in the electric Schedule 129 Low Income Program rates that became effective October 1, 2020.

Conservation Rider
The electric conservation rider mechanism, effectivecollects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 2017. The rate filing requests recovery of estimated programto collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, expenditures as well as a true-up for actual costscompared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and collections for the conservation program forcorresponding expected annual impact on PSE’s revenue based on the prior period which would result in a rate increase for electric customers of $16.5 million, or 0.7%, annually.effective dates:

Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 20221.0%$21.6
May 1, 2021(0.6)(12.3)
May 1, 20200.917.8
Electric
41


Property Tax Tracker Mechanism
On April 28, 2017,The purpose of the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism effective May 1, 2017.  The approved filing incorporatesis to pass through the effectscost of an increase toall property taxes paidincurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as well as true-ups toa tracker rate schedule and collects the ratetotal 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 which would result in ayear.
The following table sets forth property tax tracker mechanism rate decrease for electric customers of $0.9 million, or 0.04%, annually.adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2022(0.3)%$(5.8)
May 1, 2021(0.1)(1.7)
May 1, 20200.071.4

Federal Incentive Tracker Tariff
OnThe Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1.
The following table sets forth the federal incentive tracker tariff revenue requirement approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates from prior year		Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 20220.1%$(28.2)
January 1, 20210.3(29.5)
January 1, 2020(0.04)(37.8)

Low Income Program Tracker Tariff
The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket UE-011570). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas rates to reflect changes in actual sales and costs. Rates change annually on October 31, 2017,1. Included in the electric rate effective October 1, 2022, is the recovery of $25.6 million from the COVID-19 bill assistance program established in Docket U-200281 and deferred under the accounting petition approved in Docket UE-200780.
The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:

Effective Date

Average
Percentage
Increase (Decrease)
in Rates

Increase (Decrease)
in Revenue
(Dollars in Millions)
October 1, 20221.1%$25.8
October 1, 20210.35.8

42

Residential Exchange Benefit
The residential exchange program passes through the residential exchange program benefits that PSE filedreceives 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 DateAverage
Percentage
Increase (Decrease)
in Rates		Total credit to be passed back to eligible customers
(Dollars in Millions)
November 1, 20210.4%$(75.7)

Natural Gas Rates
Conservation Rider
The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conversation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 20220.3%$3.2
May 1, 2021(0.2)(1.5)
May 1, 20200.43.5

Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE's revenue based on the effective dates:
Effective DateAverage Percentage Increase (Decrease) in RatesIncrease (Decrease) in Revenue (Dollars in Millions)
May 1, 20220.02%$0.2
May 1, 20210.33.2
May 1, 2020(0.3)(2.8)
43


Cost Recovery Mechanism
The purpose of the cost recovery mechanism (CRM) is to recover costs related to projects included in PSE's pipeline replacement program plan on file with the Washington Commission an annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2018. The proposed true-up filing, as originally filed, resulted in a total credit of $48.2 million to be passed back to eligible customers over the twelve months beginning January 1, 2018. The total credit includes $37.8 million which represents the pass-back of grant amortization and $10.4 million represents the pass through of interest. This filing represents an overall average rate increase of 0.2%, annually.
On December 22, 2016, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2017. The true-up filing resulted in a total credit of $51.7 million to be passed back to eligible customers over the twelve months beginning January 1, 2017.  The total credit includes $38.1 million which represents the pass-back of grant amortization and $13.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2016 rate period.  This filing represents an overall average rate increaseintended effect of 0.3%, annually.

Residential Exchange Benefit
On September 28, 2017, the Washington Commission approved the rate filing to PSE's Residential Exchange Benefit Tariff, with an effective date of October 1, 2017. The filing resulted in a total credit of $80.8 million to be passed back to eligible customers over the twelve months beginning October 1, 2017.  This filing represents an overall average rate decrease of 0.6%, annually.
On September 24, 2015, the Washington Commission approved the rate filing to PSE's Residential Exchange Benefit Tariff, with an effective date of October 1, 2015. The filing resulted in a total credit of $76.4 million to be passed back to eligible customers over the twelve months beginning October 1, 2015.  This filing represents an overall average rate increase of 2.4%, annually.

Power Cost Update Compliance Filing
On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission's Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC. The filing requested a reduction in Schedule 95 rates of $37.3 million or an overall rate decrease of 1.7% annually. A corresponding reduction in the PCA Mechanism Baseline Rate used to track the PCA imbalance for sharing was also requested in this filing. PSE’s rate filing became effective on December 1, 2016 by operation of law.

Natural Gas Rates
Natural Gas Conservation Rider
On April 28, 2017, the Washington Commission approved PSE's annual filing request to change rates under its natural gas conservation rider mechanism, effective May 1, 2017. The rate filing requests recovery of estimated program year expenditures as well as a true-up for actual costs and collections for the conservation program for the prior period which would result in a rate decrease for natural gas customers of $1.0 million, or 0.1%, annually.

Natural Gas Property Tax Tracker Mechanism
On April 28, 2017, the Washington Commission approved PSE's annual filing request to change rates under its natural gas property tax tracker mechanism, effective May 1, 2017, which would result in a rate decrease for natural gas customers of $1.1 million, or 0.1%, annually.

Natural Gas Cost Recovery Mechanism
On October 26, 2017, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2017. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system. The impact toRates change annually on November 1. In its 2022 GRC, PSE has requested recovery of its natural gas CRM investments in the multiyear rate plan and, if approved, will no longer use the CRM annual filing to recover these pipeline replacement program investments.
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 DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20220.4%$4.6
November 1, 20210.54.9
November 1, 20201.210.6

Purchased Gas Adjustment
PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times of the year if needed.
On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $4.9$59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, or 0.5%, annually.and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million.
The annual 2021 PGA rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC.
On October 27, 2016,21, 2022, PSE filed with the Washington Commission to change PGA rates effective November 1, 2022. As part of that filing, PSE requested an annual revenue increase of $155.3 million; where PGA rates, under Schedule 101, increase annual revenue by $142.1 million, and the tracker rates under Schedule 106, increase annual revenue by $13.2 million.


The following table presents the PGA mechanism balances and activity at September 30, 2022 and December 31, 2021:
(Dollars in Thousands)September 30,December 31,
PGA receivable balance and activity20222021
PGA receivable beginning balance$57,935 $87,655 
Actual natural gas costs295,795 364,775 
Allowed PGA recovery(305,458)(396,236)
Interest1,154 1,741 
PGA receivable ending balance$49,426 $57,935 

44

The following table sets forth the PGA rate adjustments approved PSE's CRMby the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 202214.9%$155.3
November 1, 20215.859.1
November 1, 20207.770.0
October 1, 2020(3.9)(35.5)

Low Income Program Tracker Tariff
The Low Income Tracker Tariff recovers changes in costs for the low income bill payment assistance program (as approved in Washington Commission Docket UG-011571). The annual filing requests these changes through the existing low income program funding mechanism previously approved by the Washington Commission. The mechanism allows PSE to periodically adjust its electric and natural gas tariff filingrates to reflect changes in actual sales and costs. Rates change annually on October 1.
The following table sets forth the low income program funding adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE's revenue based on the effective dates:

Effective Date

Average
Percentage
Increase (Decrease)
in Rates

Increase (Decrease)
in Revenue
(Dollars in Millions)
October 1, 2022(0.04)%$(0.4)
October 1, 2021(0.3)(3.0)

Other Proceedings
Voluntary Long-Term Renewable Energy
PSE offers Green Direct to larger customers (aggregated annual loads greater than 10,000-megawatt hours (MWh)) and government customers. The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW, which went into operation on November 7, 2020. The project is fully subscribed and the twenty-one customers under phase 1 of the program began taking service in November 2020.
The Washington Commission approved a second phase of the Green Direct product in 2018. The phase 2 project is the 150 MW Lund Hill Solar facility located in Klickitat County, Washington. The solar facility achieved full commercial operations on October 19, 2022 and will serve an additional twenty customers who enrolled in 2018. On March 1, 2021, the associated power purchase agreement went into effect under an interim supply agreement for renewable energy delivered to PSE’s system; and thus, the phase 2 customers began receiving renewable energy under their agreement on March 1, 2021. All Green Direct customers are now receiving a blend of the phase 1 wind and the renewable energy delivered under the phase 2 power purchase agreement.

Crisis Affected Customer Assistance Program
On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective date of November 1, 2016.electric and natural gas service tariffs. The purpose of this filing iswas to recover capital costs relatedincorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP-1) (Dockets UE-200331 and UG-200332), to enhancingmitigate the safetyeconomic impact of the natural gas distribution system.COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to the CRM rates is an annual revenue increase of $5.6 million, or 0.6%, annually.September 30, 2020.

45
Purchased Gas Adjustment

On October 26, 2017,March 28, 2021, the Washington Commission approved PSE's PGAPSE’s CACAP-2 (Dockets UE-210137 and UG-210138). With a program budget of $20.0 million for electric customers and $7.7 million for natural gas tariff filing with an effective date of November 1, 2017,customers, CACAP-2, which reflects changesran from April 12, 2021, to March 29, 2022, provided up to $2,500 in wholesale natural gas and pipeline transportation costs and changesbill assistance in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $30.8 million, or 3.3%, annually with no impact on net operating income.arrearages per year for each qualifying low-income household.
On October 27, 2016,15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (Dockets UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved PSE's PGAthe Supplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program (HELP), with a combined total budget of $34.5 million for both electric and natural gas tariff filingresidential customers (capped at $23.7 million and $10.8 million, respectively). Supplemental CACAP benefits offered to cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an effective date of November 1, 2016, which reflects changesopt-out option, in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $4.1 million, or 0.4%, annually with no impact on net operating income.December 2021.
For additional information, see Note 6,7, "Regulation and Rates" in the Combined Notes to the consolidated financial statementsConsolidated Financial Statements included in Item 1 of this report.


Other Factors and Trends
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 renewrefinance existing or issue new long-term debt, obtain access to new or renew existing credit facilities and could increase the cost of suchissuing 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 acquisitions, including 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. As of September 30, 2017, PSE's credit facilities

were scheduled to mature in 2019 and Puget Energy's senior secured credit facility to mature in 2018. In October 2017, PSE and Puget Energy each entered into new 5 year credit facilities that replaced the current facilities and are scheduled to mature in October 2022. Additional information on credit facilities is set forth below in the “Puget Sound Energy - Credit Facilities” and "Puget Energy - Credit Facility" sections.


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 PSE's operations, including protection of air and water quality, including climate change mitigation 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, site remediation, energy and emissions monitoring, pollution control equipment and emissions-relatedpollution-related abatement and fees.
Compliance with these or other future laws and regulations, such asparticularly those pertaining to climate change mitigation, 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 and regulated monopoly. However, PSE faces competition from public utility districts and municipalities or efforts by citizens organizing to form such entities that want to establish their own municipal-ownedgovernment-owned utility, as a result of which PSE may lose a number of customers. Further, PSE also faces increasing competition for sales to its retail customers.  Alternativecustomers through alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.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.


46

Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the three months and nine months ended September 30, 2022 and September 30, 2021.

Non-GAAP Financial Measures - Electric and Natural Gas Margins
The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP),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.presentation that is not defined by GAAP.  The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance.  Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to maintain electric and natural gas margins to ultimately 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.



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


Puget Sound Energy
(Dollars in Thousands)Three Months Ended
September 30,		Nine Months Ended
September 30,
2022202120222021
Operating income (loss)$(24,637)$137,788 $399,113 $545,951 
Electric operating revenue714,122 613,386 2,064,830��1,935,800 
Purchased electricity(257,411)(190,928)(708,005)(558,853)
Electric generation fuel(105,551)(92,883)(212,693)(209,749)
Residential exchange15,712 16,491 55,565 59,885 
   Utility electric margin (non-GAAP)$366,872 $346,066 $1,199,697 $1,227,083 
Natural gas operating revenue128,665 122,808 791,067 710,838 
Purchased natural gas(38,821)(35,518)(308,606)(253,362)
   Utility natural gas margin (non-GAAP)$89,844 $87,290 $482,461 $457,476 
Other operating revenue10,548 34,042 33,216 53,074 
Unrealized gain (loss) on derivative instruments, net(62,709)88,517 59,939 172,795 
Utility operation and maintenance(157,246)(143,873)(488,479)(454,580)
Non-utility expense and other(10,673)(23,920)(35,329)(42,290)
Depreciation and amortization(190,174)(181,863)(573,934)(611,989)
Taxes other than income taxes(71,099)(68,471)(278,458)(255,618)
Operating income (loss)$(24,637)$137,788 $399,113 $545,951 


47

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 tablechart displays the details of PSE's electric margin changes:changes for the three months ended September 30, 2021 and 2022:
Electric MarginThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Electric operating revenue:          

Residential sales$239,279
 $224,987
 $14,292
 $877,112
 $801,163
 $75,949
Commercial sales215,392
 214,632
 760
 656,462
 644,025
 12,437
Industrial sales27,836
 29,740
 (1,904) 83,417
 84,417
 (1,000)
Other retail sales4,839
 5,031
 (192) 14,534
 15,234
 (700)
Total retail sales487,346
 474,390
 12,956
 1,631,525
 1,544,839
 86,686
Transportation sales3,422
 2,464
 958
 9,136
 8,086
 1,050
Sales to other utilities and marketers23,716
 20,494
 3,222
 38,404
 38,032
 372
Decoupling revenue13,310
 (277) 13,587
 24,889
 34,199
 (9,310)
Other decoupling revenue1
(4,008) (11,863) 7,855
 (11,704) (14,525) 2,821
Other13,757
 10,113
 3,644
 44,085
 12,033
 32,052
Total electric operating revenues2
537,543
 495,321
 42,222
 1,736,335
 1,622,664
 113,671
Minus electric energy costs: 
  
        
Purchased electricity2
115,881
 94,849
 21,032
 425,263
 356,296
 68,967
Electric generation fuel2
66,584
 70,503
 (3,919) 152,057
 165,627
 (13,570)
Residential exchange2
(14,246) (15,577) 1,331
 (52,814) (49,093) (3,721)
Total electric energy costs168,219
 149,775
 18,444
 524,506
 472,830
 51,676
Electric margin3
$369,324
 $345,546
 $23,778
 $1,211,829
 $1,149,834
 $61,995
            
Electric Energy Sales, MWh
           
Residential sales2,081,223
 1,997,675
 83,548
 7,785,631
 7,173,224
 612,407
Commercial sales2,272,185
 2,266,420
 5,765
 6,784,797
 6,637,349
 147,448
Industrial sales316,051
 334,108
 (18,057) 913,647
 925,280
 (11,633)
Other retail sales19,879
 23,271
 (3,392) 64,217
 69,366
 (5,149)
Total energy sales to customers4,689,338
 4,621,474
 67,864
 15,548,292
 14,805,219
 743,073
___________________
1
Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.
2
As reported on PSE’s Consolidated Statement of Income.
3
Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.

psd-20220930_g3.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Three Months Ended September 30, 2017 compared2021 Compared to 20162022
Electric Operating Revenue
Electric operating revenues increased $42.2$100.7 million from the prior year primarily due to decoupling revenuean increase in sales to other utilities of $13.6$65.2 million, higheran increase in electric retail sales of $13.0$34.5 million, an increase in other decoupling revenue of $7.9$5.6 million and an increase in transportation and other electric operating revenuesrevenue of $3.6$4.9 million; partially offset by a decrease in decoupling revenue of $9.4 million. These items are discussed in detail below.
•Electric retail sales increased $13.0$34.5 million primarily due to a $7.0an increase of $25.6 million from an increase in retail electricity usage of 67,864 Megawatt Hour (MWhs) related to average retail customer growth of 13,828 customers, or 1.2%;5.0% and an increase of $8.9 million in rates compared to the prior year . The increase in retail usage was due to an increase in residential and commercial usage of $6.0 million.5.9% and 3.7%, respectively. Residential usage increased due to an increase in cooling degree days of 44.4% due to higher than normal temperatures in three months ended September 30, 2022. The increase in commercial usage was also driven by employees returning to work after business shut downs and lack of staffing in 2021 due to COVID-19. The increase in rates is primarily due to the tariffs filed pursuant to the Company's most recent Conservation rider effective May 1, 2022. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.
48


Decoupling revenue•Sales to other utilities increased $13.6$65.2 million due to an 85.8% increase in electric wholesale price driven by increases in natural gas prices nationwide that fuel natural gas-fired electric generation, following constrained supply along with increased demand from overseas markets. PSE utilized natural gas-fired generation to sell power to California in the beginning of $15.7September 2022 when California had peak Federal Energy Regulatory Commission (FERC) prices of $1,000/MW, this contributed to an increase in sales volume of 3.7%.
•Decoupling revenue decreased $9.4 million primarily attributable to a $4.8 million and $4.6 million decrease in decoupling revenue associated with thedelivery and fixed production cost (FPC) deferral of the PCA mechanism in 2017.revenues, respectively. This was partially offsetprimarily driven by $2.1 millionlower allowed revenue per customer and increased usage for delivery deferral revenues as well as increased usage for FPC deferral revenues. As a result, allowed revenues were lower than actual decoupling deferral revenues by a greater margin in lower decoupling deferrals in 2017the current year compared to 2016 due to higher electricity usage, as noted above.
the prior year.
•Other decoupling revenue increased $7.9 million due to reduced sharing of rate of return (ROR) excess earnings of $10.2 million from over earnings in 2016 as compared to no earnings sharing in 2017. This was partially offset by an increase of decoupling cash collections of $1.1 million as compared to 2016 due to an additional $9.0 million being set into rates.
Other electric operating revenue increased $3.6$5.6 million primarily due to generationdecreased amortization of prior year undercollections. This was driven by decreased amortization rates. Additionally, the amortization of prior year overcollections from residential customers began in May 2022, which further increased other decoupling revenue.
•Transportation and other revenue increased $4.9 million primarily due to a production tax credit (PTC) deferral of $5.0$16.1 million increase in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017.non-core natural gas financial hedging gains. This was partially offset by a decrease of $8.2 million related to the IRS PLR which includes revenue recognition in net wholesale natural gas sales2021 and amortization of $1.8 million.
the PLR to offset recovery through rates in 2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report.


Electric EnergyPower Costs
Purchased electricity expenseElectric power costs increased $21.0$79.9 million primarily due to a $13.9an increase of $66.5 million of purchased electricity costs and an increase primarily related to long-term purchases and a $4.9 million increase in energy imbalance market (EIM) purchases. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind production of 21.3% and lower production at the combustion turbines of 7.8% resulted in the need to purchase power. PSE began participating in the EIM operated by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand andelectric generation resources.
Electric generation fuel expense decreased $3.9 million due to a number of factors including a $3.3 million decrease in the total cost of natural gas burned driven by lower volumes burned in 2017 as compared to 2016. Also contributing to the decrease in fuel costs is a $3.4 million decrease in the cost of coal burned from lower average prices offset by a $1.9 million increase in the lower of cost or market inventory adjustment for coal recorded in 2017 compared to 2016.


Nine Months Ended September 30, 2017 compared to 2016
Electric Operating Revenue
Electric operating revenues increased $113.7 million primarily due to higher retail sales of $86.7 million, other operating revenues of $32.1 million and other decoupling adjustments of $2.8 million; partially offset by decreases in decoupling revenue of $9.3$12.7 million. These items are discussed in detail below.
•Purchased electricity expense increased $66.5 million due to a 25.8% increase in wholesale electricity purchase volumes and an increase in average wholesale purchase prices of 7.2%. The increase in volume was driven by load and a decrease in natural gas-fired generation of 14.4% resulting from lower market heat rates as natural gas prices increased at a higher rate than power prices.
•Electric retail salesgeneration fuel increased $86.7$12.7 million primarily due to a $77.5$9.4 million increase in natural gas-fired generation fuel costs due to 30.7% higher unit production costs from higher natural gas prices, as discussed above in sales to other utilities. Additionally, Colstrip Units 3 and 4 variable fuel expense increased $3.3 million due to a 6.3% increase in coal used for production and a 18.2% increase in the average price per ton.

49

The following chart displays the details of PSE's electric margin changes for the nine months ended September 30, 2021 and 2022:
psd-20220930_g4.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Nine Months Ended September 30, 2021 Compared to 2022
Electric Operating Revenue
Electric operating revenues increased $129.0 million from the prior year primarily due to an increase in electric retail sales of $127.4 million and an increase in sales to other utilities of $55.2 million; partially offset by decreases in transportation and other revenues of $32.1 million, decoupling revenue of $19.1 million, and other decoupling revenue of $2.4 million.
•Electric retail sales increased $127.4 million due to an increase of $80.5 million in rates compared to the prior year and an increase of $46.9 million from an increase in retail electricity usage of 743,073 MWhs related2.7%. The increase in rates is primarily due to a 28.0%the tariffs filed pursuant to the Company's most recent Conservation rider and PCORC effective May 1, 2022 and July 1, 2021, respectively. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for all rate changes. The increase in retail usage was due to an increase in residential and commercial usage of 2.7% and 2.9%, respectively. Residential usage increased due to an 10.5% increase in heating degree days;days due to lower than normal temperatures, primarily in the 2nd quarter of 2022 and ana 3.2% increase in ratescooling degree days due to higher than normal temperatures, primarily in the 3rd quarter of $9.2 million.
2022. The increase in commercial usage was driven by employees returning to work after business shut downs and lack of staffing in 2021 due to COVID-19.
Decoupling revenue decreased $9.3•Sales to other utilities increased $55.2 million due to $19.8a 69.0% increase in in electric wholesale price driven by increases nationwide in prices of natural gas, that fuel natural gas-fired electric generation, following constrained supply along with increased demand from overseas markets. The increase from pricing was partially offset by lower sales volume of 13.2%, which was the result of decreased volume from natural gas-fired generation of 34.8%, driven by natural gas pricing pressure.
50

•Decoupling revenue decreased $19.1 million primarily attributable to a $5.2 million and $13.9 million decrease in delivery and FPC deferral revenues, respectively. This was primarily driven by lower allowed revenue per customer and increased usage for delivery deferral revenues as well as increased usage for FPC deferral revenues. As a result, allowed revenues were lower than actual decoupling deferral revenues by a greater margin in the current year compared to the prior year.
•Other decoupling revenue decreased $2.4 million primarily due to a $3.0 million decrease related to GAAP alternative revenue program recognition guidelines. As of the nine months ended September 30, 2021, there were $8.0 million of deferred 2020 GAAP alternative decoupling revenues that were recognized, which was partially offset by $2.0 million in lowerdeferred 2021 GAAP alternative decoupling deferralsrevenues. As of the nine months ended September 30, 2022, there were $3.0 million of deferred 2021 GAAP alternative decoupling revenues that were recognized. Additionally, other decoupling revenue increased $0.6 million due to decreased amortization of prior year undercollections.
•Transportation and other revenue decreased $32.1 million primarily due to no production tax credit (PTC) deferral revenue for the re-purpose of the PTCs in 20172022 compared to 2016 due$45.6 million in 2021 and a decrease of $32.7 million related to higher electricity usage, as noted above. This wasthe IRS PLR which includes revenue recognition in 2021 and amortization of the PLR to offset recovery through rates in 2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report. The decreases were partially offset by an increase in net wholesale non-core natural gas sales of $10.5$50.4 million, in decoupling revenue associated with the fixed cost deferral of the PCA mechanism in 2017.
Other decoupling revenue increased $2.8 millionwhich was primarily due to decreasesa $42.0 million increase in ROR excess earnings sharing of $8.6natural gas financial hedging gains. Additionally, there was a net $8.3 million increase due to no expectationwholesale non-core gas sales. The increase was due to over earna $108.6 million increase in 2017 and 24-month revenue reserve of $1.6 million from no reservewholesale sales driven by an 10.6% increase in 2017. Thisnatural gas sales volume at an average price that was partially71.6% higher in 2022 compared to 2021; wholesale non-core natural gas sales were primarily offset by a $7.4$100.3 million increase in the cost of decoupling cash collections as compared to 2016the gas sold due to an additional $9.0 million being set into rates.
higher average prices and increased volume.

Other electric operating revenueElectric Power Costs
Electric power costs increased $32.1$156.4 million primarily due to an increase of $149.2 million of purchased electricity costs, a decrease of $4.3 million of residential exchange credits and an increase of electric generation fuel costs of $2.9 million. These items are discussed in net wholesale natural gas sales of $17.3 million and a PTC deferral of $15.8 million in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017.
detail below.

Electric Energy Costs
•Purchased electricity expense increased $69.0$149.2 million primarily due to a $45.5 million increase related to long-term purchases, a $13.3 million22.2% increase in EIM purchases,wholesale electricity purchase volumes driven by a 34.5% increase in Mid-Columbia hydro energy purchases. The increase was due to load and decreased gas-fired electric generation of 34.8% caused by lower market heat rates as natural gas prices increased at a higher rate than power prices; and a $8.33.7% increase in average wholesale purchase prices.
•Electric generation fuel increased $2.9 million due to an increase in Colstrip Units 3 and 4 variable fuel expense of $7.4 million due to a 8.2% increase in coal used for production and a 14.7% increase in the average price per ton; partially offset by a $4.5 million decrease in natural gas-fired generation fuel costs as natural gas-fired generation decreased 34.8% driven by lower market heat rates as natural gas prices increased at a higher rate than power exchange contract with Pacific Gas & Electric Company. These increases wereprices; this was partially offset by 49.5% higher unit production costs due to additional load requirements and lower costshigher natural gas prices, as discussed above in sales to buy on the open market compared to generating power. Additionally, lower overall wind production of 17.4% and lower production at the combustion turbines of 26.3% resulted in the need to purchase power. PSE began participating in the EIM operatedother utilities.
•Residential Exchange credits decreased by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand and generation resources.



Electric generation fuel expense decreased $13.6$4.3 million primarily due to a $10.7 million decrease0.4% change to the amount of credits to be passed back to customers effective November 1, 2021, see Management's Discussion and Analysis, "Regulation and Rates" included in the total costItem 2 of natural gas burned driven by lower volumes burnedthis report; partially offset by an increase in the average priceresidential usage of the natural gas burned and a $2.9 million decrease in the cost of coal burned due to a lower average prices of coal burned in 2017 compared to 2016. 
Residential exchange credits increased $3.7 million resulting from increased electricity usage2.7% as rates remain consistent in both periods. The REP credit is a pass-through tariff item with a corresponding creditdiscussed above in electric operating revenue, with no impact on net income. The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.retail sales.
51


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'sPSE’s service territory. The PGA mechanism passes through increases or decreases in the natural gas supply portion of the natural gas service rates to customers based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's margin or net income is not affected by changes under the PGA mechanism because over- and under- recoveries of natural gas costs included in baseline PGA rates are deferred and either refunded to or collected from customers in future periods.
The following tablechart displays the details of PSE's natural gas margin:margin changes for the three months ended September 30, 2021 and 2022:
psd-20220930_g5.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Natural Gas MarginThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Natural gas operating revenue:          
Residential sales$65,793
 $66,480
 $(687) $467,725
 $376,310
 $91,415
Commercial sales36,617
 36,862
 (245) 194,716
 162,135
 32,581
Industrial sales3,390
 3,349
 41
 15,258
 13,742
 1,516
Total retail sales105,800
 106,691
 (891) 677,699
 552,187
 125,512
Transportation sales5,285
 4,897
 388
 16,218
 15,007
 1,211
Decoupling revenue4,840
 3,709
 1,131
 1,482
 39,739
 (38,257)
Other decoupling revenue1
(7,315) (3,904) (3,411) (12,932) (14,565) 1,633
Other2,906
 3,065
 (159) 9,218
 8,941
 277
Total natural gas operating revenues2
111,516
 114,458
 (2,942) 691,685
 601,309
 90,376
Minus purchased natural gas energy costs2
32,224
 34,041
 (1,817) 248,208
 205,418
 42,790
Natural gas margin3
$79,292
 $80,417
 $(1,125) $443,477
 $395,891
 $47,586
            
Natural Gas Volumes           
(Therms in Thousands):           
Residential42,150
 44,650
 (2,500) 412,325
 331,180
 81,145
Commercial firm31,861
 31,629
 232
 194,446
 159,096
 35,350
Industrial firm4,048
 3,626
 422
 18,444
 16,015
 2,429
Interruptible6,877
 9,452
 (2,575) 33,921
 33,829
 92
Total retail natural gas volumes, therms84,936
 89,357
 (4,421) 659,136
 540,120
 119,016
Transportation volumes53,992
 52,298
 1,694
 173,042
 170,548
 2,494
Total natural gas volumes138,928
 141,655
 (2,727) 832,178
 710,668
 121,510
_______________
1
Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.
2
As reported on PSE’s Consolidated Statement of Income.
3
Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.





Three Months Ended September 30, 2017 compared2021 Compared to 20162022
Natural Gas Operating Revenue
Natural gas operating revenuedecreased $2.9 increased $5.8 million due to increases in transportation and other revenue of $2.1 million, decoupling revenue of $2.0 million, retail sales of $1.0 million and other decoupling revenue of $0.7 million. These items are discussed in detail below.
•Natural gas retail sales revenue increased $1.0 million primarily due to an increase in rates of $10.9 million, which was partially offset by a decrease of $3.4$9.9 million due to a decrease in natural gas load of 6.1%. The increase in rates is due to the tariffs filed pursuant to the Company's most recent Conservation rider effective May 1, 2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. The decrease in load is primarily driven by a 10.2% decrease in residential usage, which was due to a decrease in heating degree days of 64.7%.
52

•Decoupling revenue increased $2.0 million primarily attributable to decreased usage in the current period compared to the same period in 2021. This resulted in actual natural gas revenues being lower than allowed natural gas revenues in the current period, whereas in the same period in 2021, actual revenues were higher than allowed revenues.
•Transportation and other revenue increased $2.1 million primarily due to LNG return deferral revenue of $5.1 million in 2022.

Natural Gas Energy Costs
•Purchased natural gas expense increased $3.3 million due to an increase in the PGA rates in November 2021 and partially offset by a decrease in natural gas usage of 6.1% as stated in the natural gas retail sales section above.














53

The following chart displays the details of PSE's natural gas margin changes for the nine months ended September 30, 2021 and 2022:
psd-20220930_g6.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.


Nine Months Ended September 30, 2021 Compared to 2022
Natural Gas Operating Revenue
Natural gas operating revenue increased $80.2 million primarily due to an increase of $93.4 million in total retail sales and a $4.9 million increase in transportation and other revenue; partially offset by a decrease of $12.0 million in decoupling revenue and a decrease of $0.9$6.1 million in total retail sales due to a decrease of natural gas usage; partially offset by a $1.1 million increase inother decoupling revenue. These items are discussed in detail below.
•Natural gas retail sales revenue decreased $0.9 increased $93.4 million primarily due to a decreasean increase in rates of $5.3$49.4 million from a reductionand an increase of 2,727 therms sold from lower heating degree days$44.0 million due to an increase in 2017; partially offsetnatural gas load of 6.2%. The increase in rates is due to the PGA increase effective November 1, 2021, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. The increase in load is driven by an increase of $4.4commercial and residential usage of 10.3% and 4.4%, respectively. The increase in commercial usage was driven by employees returning to work after business shut downs and lack of staffing in 2021 due to COVID-19. Residential usage increased due to an increase in heating degree days of 10.5% due to lower than normal temperatures in the second quarter of 2022.
•Decoupling revenue decreased $12.0 million primarily attributable to increased usage in the current period and lower allowed revenue per customer compared to the same period in 2021. This resulted in actual natural gas revenues being higher than allowed natural gas revenues in the current period, whereas in the same period in 2021, actual revenues were lower than allowed revenues.
54

•Other decoupling revenue decreased $6.1 million due to an increase in current period amortization of prior year revenues compared to the same period in 2021. This is attributable to increased usage in the current period as well as increased amortization rates, both of which increase the rate adjustments.
at which deferral revenues are recovered from customers.
Other decoupling•Transportation and other revenue decreased $3.4 increased $4.9 million primarily due to increased ROR excess earnings sharingLNG return deferral revenue of $6.2$13.8 million of which $4.3 million was accrued for over earnings in 2017. This was2022; partially offset by a decrease of $2.7$6.4 million in 24-month revenue reserve as compared to 2016 as no reserve was recorded in 2017.

Nine Months Ended September 30, 2017 compared to 2016
Natural Gas Operating Revenue
Natural gas operating revenue increased $90.4 million primarily due to an increase of $125.5 million in total retail sales due to additional natural gas usage and an increase in other decoupling revenue of $1.6 million; partially offset by a $38.3 million reduction in decoupling revenue. These items are discussed in detail below.
Natural gas retail sales revenue increased $125.5 million primarily due to an increase of $121.7 million from an additional 121,510 therms sold related to a 28.0% increase in heating degree days; and an increase of $3.8 million due to rate adjustments.
Decoupling revenue decreased $38.3 million due to lower load volumes in 2016, which caused actual revenue to be below the allowed revenue, resulting in higher decoupling revenue of $39.7 million. In 2017, higher load volumes caused actual revenue to be closer to allowed revenue resulting in lower decoupling revenue of $1.5 million.
Other decoupling revenue increased $1.6 million primarily due to a $22.9 million reversal of previously deferred revenues related to the 24-monthIRS PLR which included revenue reserve.  The increase was partiallyrecognition in 2021 and amortization of the PLR to offset by an increaserecovery through rates in decoupling cash collections2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of $13.0 million due to an additional $6.0 million being set in rates and increased ROR excess earnings sharing of $8.2 million of which $10.1 million was accrued for over earnings in 2017.
this report.


Natural Gas Energy Costs
•Purchased natural gas expense increased $42.8$55.2 million directly relateddue to a 22.7%an increase in the PGA rates in November 2021 and an increase in natural gas usage.usage of 6.2% as stated in the natural gas retail sales section above.


55

Other Operating Expenses and Other Income (Deductions)
The following tablechart displays the details of PSE's operating expenses and other income (deductions) for the three and nine months ended September 30, 20172021 and 2016:2022:
psd-20220930_g7.jpg
Puget Sound EnergyThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Operating expenses: 
  
  
      
Net unrealized (gain) loss on derivative instruments$(23) $6,327
 $(6,350) $23,098
 $(57,218) $80,316
Utility operations and maintenance141,003
 138,265
 2,738
 438,622
 422,273
 16,349
Non-utility expense and other9,994
 8,620
 1,374
 27,857
 26,474
 1,383
Depreciation and amortization120,829
 110,022
 10,807
 355,538
 328,809
 26,729
Conservation amortization25,395
 21,800
 3,595
 85,847
 77,551
 8,296
Taxes other than income taxes66,367
 65,268
 1,099
 262,099
 235,431
 26,668
Other income (deductions):           
Other income6,778
 6,131
 647
 18,861
 19,184
 (323)
Other expense(2,878) (5,025) 2,147
 (6,134) (8,488) 2,354
Interest expense(56,745) (58,212) 1,467
 (172,467) (174,673) 2,206
Income tax expense14,424
 8,393
 6,031
 109,015
 117,533
 (8,518)


Three Months Ended September 30, 2017 compared2021 Compared to 20162022
Other Operating Expenses
•Net unrealized (gain) loss on derivative instruments increased $6.4decreased $151.2 million fromto a net loss of $6.3$62.7 million due tofor the three months ended September 30, 2022. The primary driver was the change in the weighted average forward prices for electric and natural gas. Specifically, electric prices decreased 22.1% resulting in a $6.6$72.2 million increaseloss for electric. Natural gas prices decreased 28.9% resulting in a $26.4 million loss for natural gas. Additionally, the net settlements of contracts withelectric trades previously unrealized losses.
recorded as $8.3 million in gain and of natural gas trades previously recorded at a $44.3 million gain. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" in the Combined Notes to the Consolidated Financial Statements included in Item 1 of this report.
Depreciation•Utility operations and amortizationmaintenance expense increased $10.8$13.4 million primarily due to an increase of $3.7increases in the following: (i) $2.7 million of executive compensation due to additional executives, (ii) $2.4 million of other generation maintenance costs due to higher wind turbine maintenance, (iii) $2.0 million increase in the non-service cost component of the qualified pension net periodic benefit cost in 2022 compared to 2021, (iv) $1.6 million in outside consulting fees related to corporate strategy work, (v) $1.3 million of customer service expense due to higher low income assistance, (vi) $1.2 million of miscellaneous distribution expense due to higher green power program expenses and higher administrative and general expenses in 2022 as compared to 2021, due to fewer COVID-19 restrictions and return to office, (vii) $1.1 million increase in Washington Commission filing fees related to the GRC filing and (viii) $1.0 million in credit card payment and bill processing expenses.
•Non-utility expense and other expense decreased $13.2 million primarily due to $12.9 million related to the PWI land sale in 2021.
56

•Depreciation and amortization expense related increased $8.3 million due to: (i) conservation amortization increased by $5.8 million due to an increase in conservation rider rates effective May 1, 2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of computer software assets,this report, (ii) common general plant depreciation increased a net of $2.2 million of depreciation expense relatedor 32.1% from 2021 primarily due to $33.9 million in net additions of $183.0Advanced Metering Infrastructure (AMI) communication equipment, (iii) electric amortization increased by $2.0 million or 21.7% from 2021 primarily due to $19.1 million in net additions in intangible electric assets including a $16.5 million King County franchise renewal fee, (iv) electric distribution depreciation increased a net of $1.7 million or 4.4% from 2021 due to $241.4 million in net additions of electric distribution assets and general(v) natural gas distribution depreciation increased $1.3 million or 4.2% from 2021 primarily due to $189.8 million in net additions in natural gas distribution assets. The increases were partially offset by: (i) common amortization decreased by $3.5 million, which was primarily driven by $26.2 million in net retirements of 3 to 5 year life common technology assets and (ii) natural gas amortization decreased by $2.1 million driven by $1.6 million of LNG depreciation expense deferral.
•Taxes other than income taxes increased $2.6 million primarily due to a $1.6 million increase in state excise tax and an increase of $1.7$1.2 million relatedin municipal taxes, both of which were driven by the increase in retail revenue in 2022 as compared to an additional $174.8 million of natural gas distribution assets.
2021.


Other Income, Interest Expense and Income Tax Expense
Income tax•Interest expenseincreased $6.0 million primarily driven by higher pre-tax book income.


Nine Months Ended September 30, 2017 compared to 2016
Other Operating Expenses
Net unrealized (gain) loss on derivative instruments decreased $80.3 million to a loss of $23.1 million of which $57.2 million was due to decreases in average forward market prices of wholesale electricity and natural gas, and $23.1 million due to a decrease in settlements of contracts with previously unrealized losses.
Utility operations and maintenance expense increased $16.3 million, which was primarily due to the following: increases in administrative and general and customer service expense of $21.9 million primarily due to $7.1 million of rent expense primarily at the corporate office locations, $5.3 million expense primarily for liability claims and insurance premium, $4.6 million of pensions and benefits expense, $3.9 million of general plant maintenance expense and $3.1 million of outside services employed expenses. This was partially offset by a decrease in electric transmission and distribution expense of $8.4 million.
Depreciation and amortization expense increased $26.7$6.2 million primarily due to an increase of $11.6$2.7 million of amortization expense related to anthe PSE $450.0 million senior secured notes issued on September 15, 2021 and a $1.2 million increase related to interest expense recognized in conjunction with PSE's deferred compensation liability.
•Income tax expense decreased $27.4 million primarily driven by a decrease in pre-tax book income.




























57

The following chart displays the details of computer software assets, $8.7PSE's operating expenses and other income (deductions) for the nine months ended September 30, 2021 and 2022:

psd-20220930_g8.jpg

Nine Months Ended September 30, 2021 Compared to 2022
•Net unrealized (gain) loss on derivative instruments decreased $112.9 million to a net gain of depreciation expense due to$59.9 million for the nine months ended September 30, 2022. The primary driver was the change in the weighted average forward prices for electric and natural gas. Specifically, electric prices decreased 34.3% resulting in $37.2 million loss for electric. Natural gas prices decreased 26.1% resulting in a $23.0 million gain, as the gain in the first quarter of 2022 offset losses generated in the second and third quarter of 2022. Additional losses were driven by the net additions of $253.7 millionsettlement of electric transmission, distributiontrades previously recorded as $22.3 million in gain and general assets and an increase of $5.0 million of depreciation expense due to net additions of $174.8 million of natural gas distribution assets.
trades previously recorded as $76.4 million in gain. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" in the Combined Notes to Consolidated Financial Statements included in Item 1 of this report.
Taxes other than income taxes•Utility operations and maintenance expense increased $26.7$33.9 million primarily due to increases in municipal taxesthe following: (i) $7.9 million of $9.2other generation maintenance costs due to increased wind turbine maintenance, (ii) $5.6 million in supervision, support and state excise taxes of $8.5 million bothIT costs related to technology growth and resumption of training and travel expenses in 2022 due to fewer COVID-19 restrictions and return to office, (iii) $4.6 million increase in the non-service cost component of the qualified pension net periodic benefit cost, (iv) $4.3 million in Washington Commission and GRC related legal expense, (v) $2.7 million of underground line maintenance due to emergent outages response and restoration costs, (vi) $2.7 million of customer service expense due to low income assistance funding, (vii) $2.4 million of miscellaneous distribution expenses due to higher green power program expenses and administrative and general expenses, (viii) $2.1 million of distribution overhead line expense due to increased revenueengineering and emergent electric work on overhead lines, (ix) $2.0 million of maintenance of general electric plant due to higher software and hardware expenses and (x) $1.5 million in credit card processing fees and call center related expenses. These increases were partially offset by a decrease of $4.7 million in overhead line maintenance due to fewer storm events in 2022 compared to 2021.
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•Non-utility expense and other expense decreased $7.0 million primarily due to $12.9 million related to the PWI land sale in 2021. This decrease was partially offset by: (i) an increase of $3.8 million related to biogas purchase expense and (ii) an increase for the long-term incentive plan of $2.0 million due to estimated performance results, as compared to the prior year.
•Depreciation and amortization expense decreased $38.1 million due to: (i) electric amortization decreased by $41.3 million, which was primarily driven by $45.6 million less PTC amortization in 2022 as PSE fully utilized its PTC balance in 2021, (ii) common amortization decreased by $15.7 million, primarily driven by $26.2 million in net retirements of 3 to 5 year lived common technology assets and (iii) natural gas amortization decreased by $4.8 million, primarily driven by $3.9 million of LNG depreciation expense deferral. The decreases were partially offset by (i) common general plant depreciation increased by a net of $6.0 million or 29.2% from 2021 primarily due to $33.9 million in net additions of AMI communication equipment, (ii) conservation amortization increased by $5.9 million due to an increase in retail usage of 2.7% and 6.2% for electric and natural gas, respectively; and an increase in conservation rider rates effective May 1, 2022, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report, (iii) electric distribution depreciation increased by a net of $4.5 million, primarily due to $241.4 million in net additions of electric distribution assets, (iv) natural gas distribution depreciation increased by $4.0 million, primarily due to $189.8 million in net additions in natural gas distribution assets and (v) electric production depreciation increased by a net of $2.7 million, primarily due to $10.7 million in net additions of electric production assets.
•Taxes other than income taxes increased $22.8 million primarily due to a $11.0 million increase related to municipal taxes and an increase of $8.8$9.1 million in property taxes related to increased property values and expectedthe state excise tax rates.
driven by the increase in retail revenue in 2022 as compared to 2021.

Other Income, Interest Expense and Income Tax Expense
Income tax •Other income/expensedecreased $8.5 increased $5.1 million primarily driven by lowerincreases of (i) $4.9 million in interest expense related to the deferred return for Puget LNG, per Washington Commission Docket UG-210918, (ii) $4.0 million in Washington Commission allowance for funds used during construction (AFUDC) due to a 27.6% increase in eligible CWIP and (iii) $1.9 million in the North American Electric Reliability Corporation standards compliance loss reserve in 2022 as compared to 2021. These increases were partially offset by an increase of $4.6 million in the non-service cost component of the qualified pension net periodic benefit cost for 2022 compared to 2021.
•Interest expense increased $6.0 million primarily driven by increases of (i) $9.2 million related to the PSE $450.0 million senior secured notes issued on September 15, 2021 and (ii) $1.7 million in finance lease interest expense. These increases were partially offset by: (i) a decrease of $3.1 million in monetized PTC interest expense and (ii) a decrease of $1.4 million related to the Lower Snake River treasury grant interest expense.
•Income tax expense decreased $19.9 million primarily driven by a decrease in pre-tax book income.
59


Puget Energy
Primarily, all operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and nine months ended September 30, 20172021 and 2016 are2022 is as follows:

Benefit/(Expense)Three Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
PSE net income$29,100
 $18,977
 $10,123
 $222,846
 $256,382
 $(33,536)
Non-utility expense and other2,675
 3,912
 (1,237) 9,200
 10,956
 (1,756)
Other income (deductions)374
 (316) 690

512
 (316) 828
Non-hedged interest rate swap (expense)—
 563
 (563) 28
 (651) 679
Interest expense1
(28,913) (28,384) (529) (85,451) (84,451) (1,000)
Income tax benefit (expense)9,600
 7,583
 2,017
 28,527
 26,154
 2,373
Puget Energy net income (loss)$12,836
 $2,335
 $10,501
 $175,662
 $208,074
 $(32,412)
psd-20220930_g9.jpg
_______________
1
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on long-term debt.

Summary Results of Operation
Three Months Ended September 30, 20172021 compared to 20162022
Puget Energy’s net income increased for the three months ended September 30, 2017 by $10.5 million primarily due to PSE's increase in net income. No additional factors significantly impacted Puget Energy's net income.

Nine Months Ended September 30, 2017 compared to 2016Summary Results of Operation
Puget Energy’s net income decreased by $143.3 million, which is primarily attributable to a decrease in PSE's net income of $141.9 million, an increase in PLNG net loss of $4.6 million due to additional operational expenses as PLNG commenced commercial operations in February 2022 and an increase in income tax expense of $3.9 million due to a decrease in net loss in 2022. The decreases to PE results of operations were partially offset by a decrease in interest expense of $7.8 million which is a result of lower interest rates on outstanding debt as Puget Energy repaid $450.0 million 5.625% notes and issued $450.0 million 4.224% notes in March 2022. See Management's Discussion and Analysis, "Financing Program" included in Item 2 of this report for further details.

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Puget Energy's net income (loss) for the nine months ended September 30, 20172021 and 2022 is as follows:
psd-20220930_g10.jpg

Nine Months Ended September 30, 2021 compared to 2022
Summary Results of Operation
Puget Energy’s net income decreased by $32.4$142.7 million, which is primarily attributable to a decrease in PSE's net income of $138.0 million, an increase in net loss of $12.7 million at PLNG due to PSE'sadditional operational expenses as PLNG commenced commercial operations in February 2022, and an increase in income tax expense of $8.1 million due to a decrease in net income. No additional factors significantly impactedloss in 2022. The decreases were partially offset by a decrease in interest expense of $17.5 million which is a result of lower interest rates on outstanding debt as Puget Energy's net income.Energy repaid $500.0 million of 6.00% notes and issued $500.0 million of senior secured notes at an interest rate of 2.379% in June 2021. Additionally, Puget Energy repaid a $210.0 million term loan in June, 2021. See Management's Discussion and Analysis, "Financing Program" included in Item 2 of this report for further details.













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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, 2016,2021, during the nine months ended September 30, 20172022, the Company has entered into two new power supplyElectric Portfolio and serviceElectric Wholesale Market Transaction contracts with estimated payment obligations totaling $729.5$466.6 million through 2028.2031.
For further information, see Part II, Item 8, Note 16, "Commitments and Contingencies" in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.

The following are the Company's aggregate availability under commercial commitments as of September 30, 2017:2022:
Puget Energy and
Puget Sound Energy		Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)TotalLess than 1 Year1-3 Years3-5 YearsThereafter
Commercial commitments:
PSE revolving credit facility$800,000 $— $— $800,000 $— 
Inter-company short-term debt30,000 — — — 30,000 
Total PSE commercial commitments830,000 — — 800,000 30,000 
Puget Energy revolving credit facility706,700 — — 706,700 — 
Less: Inter-company short-term debt elimination(30,000)— — — (30,000)
Total Puget Energy commercial commitments$1,506,700 $— $— $1,506,700 $— 
Puget Sound Energy and
Puget Energy
Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)Total 2017 2018-2019
 2020-2021
 Thereafter
PSE working capital facility1
$650,000
 $—
 $650,000
 $—
 $—
PSE energy hedging facility1
350,000
 —
 350,000
 —
 —
Inter-company short-term debt2
30,000
 —
 —
 —
 30,000
Total PSE commercial commitments$1,030,000
 $—
 $1,000,000
 $—
 $30,000
Puget Energy revolving credit facility3
716,936
 —
 716,936
 —
 —
Less: Inter-company short-term debt elimination2,3
(30,000) —
 —
 —
 (30,000)
Total Puget Energy commercial commitments$1,716,936
 $—
 $1,716,936
 $—
 $—

_______________For further discussion, see Management's Discussion and Analysis, "Financing Program" in Item 2 of this report.
1
For more information, see "Financing Program - Puget Sound Energy - Credit Facilities - set forth below
2
For more information, see "Financing Program - Puget Sound Energy - Demand Promissory Note - set forth below.
3
For more information, see "Financing Program - Puget Energy - Credit Facility - set forth below.


Off-Balance Sheet Arrangements
As of September 30, 2017,2022, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition, other than previously disclosed items in Note 8, "Commitment and Contingencies" to the consolidated financial statements included in Item 1 of this report.condition.


Utility Construction Program
PSE’sThe Company’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to support reliable energy delivery, meet regulatory requirements, support customer growth and customer growth.to improve energy system reliability.  The Company adjusted capital expenditures, resulting in a decrease of $71.7 million compared to forecasted amounts for the nine months ended September 30, 2022. The decrease was primarily due to (i) project and permitting delays for the Lower Baker Dam grouting project, which is being pursued in order to comply with the FERC dam safety standards and to extend the life of the project to meet the 50 year FERC license; (ii) timing related variances with IT Data Center hardware refresh, and (iii) timing of the Dupont pipe replacement program. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC),AFUDC, totaled $677.0$721.8 million for the nine months ended September 30, 2017.2022. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections     Capital Expenditure Projections
(Dollars in Thousands)2017 2018 2019
(Dollars in Millions)(Dollars in Millions)202220232024
Total energy delivery, technology and facilities expenditures$1,092,000
 $972,000
 $809,000
Total energy delivery, technology and facilities expenditures$973.9$1,293.1$1,292.1


The program is subject to change based upon general business, economic and regulatory conditions.  Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources which may include

cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  

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Capital Resources
Cash from Operations
Puget Sound EnergyNine Months Ended September 30, 2017Puget Sound EnergyNine Months Ended
September 30,
(Dollars in Millions)2017 2016 Change
(Dollars in Thousands)(Dollars in Thousands)20222021Change
Net income$222,846
 $256,382
 $(33,536)Net income$213,950 $351,959 $(138,009)
Non-cash items1
562,232
 455,355
 106,877
Non-cash items1
429,194 391,584 37,610 
Changes in cash flow resulting from working capital2
164,451
 66,718
 97,733
Changes in cash flow resulting from working capital2
38,038 68,070 (30,032)
Regulatory assets and liabilities(83,370) (138,096) 54,726
Regulatory assets and liabilities11,210 (87,076)98,286 
Other noncurrent assets and liabilities3
(33,734) 10,128
 (43,862)
Purchased gas adjustmentPurchased gas adjustment8,509 31,387 (22,878)
Other non-current assets and liabilities3
Other non-current assets and liabilities3
(26,034)(9,484)(16,550)
Net cash provided by operating activities$832,425
 $650,487
 $181,938
Net cash provided by operating activities$674,867 $746,440 $(71,573)
_______________
1
Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments and AFUDC-equity.
2
Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.
3
Other noncurrent assets and liabilities include funding of pension liability.

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.

Nine Months Ended September 30, 20172022 compared to 20162021
Cash generated from operations for the nine months ended September 30, 2017 increased2022 decreased by $181.9$71.6 million including a net income decrease of $33.5$138.0 million. The following are significant factors that impacted PSE's cash flows from operations:
•Cash flow adjustments resulting from non-cash items increased $106.9$37.6 million primarily due to: (i) a $112.9 million change from a net unrealized gain on derivative instruments of $172.8 million to a net unrealized gain on derivative instruments of $59.9 million, (ii) a $45.6 million change in PTC utilization, (iii) $24.7 million related to recognition of regulatory asset in 2021 as a result of the IRS PLR that concluded the EDIT methodology included in rates following the 2019 GRC order was impermissible, (iv) an increase of $5.9 million in conservation amortization and (v) a $1.2 million change in amortization of Tax Cuts and Jobs Act over collection. The increases were partially offset by: (i) a decrease in depreciation and amortization of $43.9 million, (ii) a decrease in deferred income taxes of $78.9 million, (iii) a deferral of return and depreciation expenses for PSE's share of Tacoma LNG investment of $8.9 million, (iv) a $18.9 million decrease due to deferral of energy exchange cost, (v) equity AFUDC of $2.1 million. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2 of this report.
•Cash flows resulting from changes in working capital decreased $30.0 million primarily due to changes in derivative instrumentsaccounts payable and taxes payable, which decreased faster than the same period last year that led to increased cash outflows of $80.3$42.2 million and depreciation$25.2 million, respectively. In addition, higher balances in materials and amortizationsupplies and fuel and natural gas inventory increased cash outflows by $12.6 million and $26.6 million respectively. The cash outflows were partially offset by a cash inflow of $26.7 million.
Cash flow resulting from working capital increased $97.7$23.7 million due to changes inthe timing of accounts receivable unbilled revenue, materialscollections, as the balance of account receivable decreased $126.5 million in the nine months ended September 30, 2022 compared to a decrease of $102.8 million during the same period of 2021. Further cash inflows were due to (i) deferral of energy exchange costs and supplies, prepayments, purchased gas adjustmentsdecreases in other prepayment expenses of $34.6 million, (ii) higher accrued salary and accrued expenses.wage expenses of $10.1 million, (iii) increased annual Washington Commission filing fee payables of $4.2 million and (iv) landlord incentives added $2.9 million cash flow.
•Cash flowflows resulting from regulatory assets and liabilities increased $54.7$98.3 million primarily due to: (i) a $22.0 million increase in the power cost adjustment mechanism, (ii) lower decoupling deferrals and higher decoupling cash collection in the first nine months of 2022 compared to changessame period in decoupling2021, which resulted in $30.9 million cash inflow together, (iii) a $19.1 million cash inflow was related to a deferral of storm excess costs in 2021, (iv) a $12.7 million increase in low income program as result of accrued higher cost in 2021 to assist pandemic (COVID-19) affected families, (v) lower expenses and derivativeshigher amortization led to an increase of $13.0 million cash inflow in property tax tracker, (vi) amortizing IRS PLR deferral balances contributed an addition of $14.4 million cash inflow, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report. The cash inflows were partially offset by changes ina cash outflow of $10.7 million related to major maintenance, which was due to scheduled major inspections at several generation stations.
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•Cash flow resulting from purchased gas adjustments.adjustment decreased $22.9 million, which was driven by an increase in actual gas cost that exceeded the increase in allowed PGA recovery in 2022 compared to 2021. Increased natural gas prices led to an $76.7 million, or 34.8%, increase in actual gas costs in 2022 compared to 2021. Meanwhile, the total amount of allowed PGA recovery in 2022 increased only $53.8 million, or 21.4%, compared to 2021. The combined effect led to year-over-year cash outflow.
•Cash flow resulting from other non-current assets and liabilities decreased $16.6 million, which was mainly driven by the $11.0 million PWI land sale in Tumwater, Washington in 2021. In addition, a $2.4 million decrease was associated with fees paid for the new $800 million credit facility to replace the existing facility that PSE entered on May 16, 2022. Changes in accrual of other long-term expenses led to a decrease of $3.2 million.

Puget EnergyNine Months Ended
September 30,
(Dollars in Thousands)20222021Change
Net income$(62,861)$(58,155)$(4,706)
Non-cash items1
34,777 7,747 27,030 
Changes in cash flow resulting from working capital2
11,380 (16,937)28,317 
Other non-current assets and liabilities3
(7,008)(7,964)956 
Net cash provided by operating activities$(23,712)$(75,309)$51,597 
_______________
1 Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and
other miscellaneous non-cash items.
2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, PGA, accounts payable and accrued expenses.
3 Other noncurrent assets and liabilities decreased $43.9 million primarily due to changes in asset retirement obligations andinclude funding of pension funding partially offset by changes in long-term deferred credits.liability.
Puget EnergyNine Months Ended September 30, 2017
(Dollars in Millions)2017 2016 Change
Net income$175,662
 $208,074
 $(32,412)
Non-cash items1
534,975
 425,634
 109,341
Changes in cash flow resulting from working capital2
151,128
 67,968
 83,160
Regulatory assets and liabilities(83,370) (138,096) 54,726
Other noncurrent assets and liabilities3
(9,725) 6,766
 (16,491)
Net cash provided by operating activities$768,670
 $570,346
 $198,324
_______________
1
Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments and AFUDC-equity.
2
Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.
3
Other noncurrent assets and liabilities include funding of pension liability.

Nine Months Ended September 30, 20172022 compared to 20162021
Cash generated from operations for the nine months ended September 30, 20172022, in addition to the changes discussed at PSE above, increased by $198.3$51.6 million compared to the same period in 2016.2021, which includes a net income decrease of $4.7 million.  The net differenceremaining change was primarily impacted by the increase from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance isfactors explained below:
•Non-cash items increased $27.0 million primarily due to higher non-cash inflows of $23.1 million related to changes in deferred taxes and an increase in amortization and depreciation of $3.9 million.
•Cash flow resulting from working capital decreased $14.6 increased $28.3 million primarily due toto: (i) a larger$15.6 million increase, which was caused by the change in accounts receivable.

Cash flow resulting from other noncurrent assetsPSE's intercompany account receivable and liabilities increased $27.4 million primarily due toaccount payable balances with Puget LNG and Puget Energy, which are eliminated upon consolidation of Puget Energy, (ii) changes in other propertytax payable added $8.3 million cash inflow, (iii) an increased cash inflow of $5.5 million, which was driven by reduction of accrued interest expense as result of lower interest rates on debt, as Puget Energy repaid $500.0 million of 6.00% notes and investments relatedissued $500.0 million of senior secured notes at an interest rate of 2.379% in June, 2021. Additionally, Puget Energy used an equity contribution from Puget Equico to Puget LNG.pay off a $210.0 million term loan in June, 2021. See Management's Discussion and Analysis, "Financing Program" included in Item 2 of this report for further details.


Financing Program
The Company'sCompany’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'sEnergy’s and PSE'sPSE’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 and operations 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.
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As a result of the 2019 GRC outcome and the continuing negative impacts of tax reform on the Company's cash flows, Puget Energy and PSE's credit rating metrics were negatively impacted. In response to the 2019 GRC order, Moody's released an issuer comment stating the GRC outcome was credit negative but took no formal credit rating action. On July 23, 2020, S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome, but later revised to negative outlook. Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. On May 27, 2021, S&P revised Puget Energy’s and PSE’s ratings from negative to stable outlook. On June 1, 2021, Fitch also revised its outlook for PE and PSE to stable. Both actions were a result of the passage and signing into law of Washington Senate Bill 5295 which allows for multi-year rate plans and reduction of regulatory lag, as well as other actions taken by management to increase revenue via available rate recovery methods and management of internal expenses. Despite these actions, the rating agencies noted that a lack of sufficient regulatory rate relief over the relative near term could result in negative ratings implications. Although neither Puget Energy nor PSE have any debt whose maturity would be accelerated upon a ratings downgrade, a credit rating downgrade may increase the cost of borrowing for Puget Energy and PSE in future long-term financings or under their existing credit facilities. Any increase in the cost of borrowing may negatively impact Puget Energy and PSE's future results of operations and could negatively impact their future liquidity, access to debt capital resources and financial condition. Additionally, a ratings downgrade could impact the Company's ability to issue dividends, see Dividend Payment Restriction below for further details. A downgrade to Puget Energy and PSE's credit ratings would not impact debt covenants under our existing credit facilities nor would it impact other contracts, as neither include credit rating triggering event clauses. A credit rating decrease for PSE could result in increased cash collateral required for commodity contracts, which would adversely affect PSE's liquidity. Management continually monitors the credit rating environment for both Puget Energy and PSE, but cannot predict with certainty the actions credit agencies may take, if any, in response to weaker near term credit metrics, regulatory and rate recovery uncertainties, and management's efforts to contain the growth of capital and operating expenditures. Containing the growth of capital and operating expenditures will be limited, over the near term, due to continuing strategic and risk mitigation imperatives and the necessity of providing safe, reliable and resilient service levels to customers, particularly in the context of the COVID-19 pandemic.

Puget Sound Energy
Credit FacilitiesFacility
As of September 30, 2017,On May 16, 2022, PSE had two unsecured revolving credit facilities which provided, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consisted ofentered into a $650.0new $800 million revolving liquidity facility (which included a liquidity letter of credit facility to replace the existing facility. The terms and a swingline facility)conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the Secured Overnight Funding Rate (SOFR), as the London Interbank Offer Rate (LIBOR) is being discontinued in 2023. The proceeds of the PSE credit facility are to be used for general corporate purposes, including as backstop topurposes. The maturity date of the Company's commercial paper program and a $350.0 million revolving energy hedgingcredit facility (which included an energy hedging letter ofis May 14, 2027. The credit facility). The $650.0 million liquidity facility includedincludes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also hadmillion and has an accordionexpansion feature which, upon the banks' approval, wouldreceipt of commitments from one or more lenders, could increase the total size of these facilitiesthe facility up to $1.5$1.4 billion. These unsecured revolving credit facilities mature in April 2019.
The credit agreements areagreement is syndicated among numerous lenders and containcontains 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 agreementsagreement also containcontains a financial covenantleverage ratio that requires the ratio of (a) total debtfunded indebtedness to (b) total capitalization ofto be 65.0% or less.less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2017,2022, PSE was in compliance with all applicable covenant ratios.
The credit agreements provideagreement provides PSE with the ability to borrow at different interest rate options. The credit agreements allowagreement allows PSE to borrow at the bank'sa prime based rate or to make floating rate advances at London Interbank Offered Rate (LIBOR)the SOFR, in either case, plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities.facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBORSOFR is 1.25% and the commitment fee is 0.175%.
As of September 30, 2017,2022, no amounts wereamount was drawn and outstanding under either facility. No letters ofPSE's credit were outstanding under either facility and $139.0$102.0 million was outstanding under the commercial paper program. Outside of the credit agreements,agreement, PSE had a $3.1$2.3 million letter of credit in support of a long-term transmission contract and a $1.0had $15.0 million issued under the standby letter of credit in support of natural gas purchases in Canada.with TD Bank.
In October 2017, PSE entered into a new $800.0 million credit facility to replace the two existing facilities. The new credit facility consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant, and accordion feature remain substantially the same. The new facility matures in October 2022.


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'sPSE’s outstanding commercial paper interest rate or PSE'sPSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of September 30, 2017,2022, PSE had no outstanding balance under the Note.


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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 September 30, 2017,2022, PSE could issue:
•Approximately $2.6$1.7 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3$2.8 billion of electric bondable property available for issuance, subject to a minimuman interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at September 30, 2017;2022; and
•Approximately $545.0$891.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $908.3 million$1.5 billion of natural gas bondable property available for issuance, subject to a minimum 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 September 30, 2017.2022.
At September 30, 2017,2022, PSE had approximately $6.9$8.3 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.


Shelf Registrations
On November 21, 2016,In August 2022, PSE filed aan S-3 shelf registration statement under which it may issue as of the date of this report, up to $800.0 million$1.4 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $1.4 billion was available to be issued. The shelf registration will expire in November 2019.August 2025.


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 September 30, 2017,2022, approximately $674.2 million$1.3 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
PursuantBeginning February 6, 2009, pursuant to the terms of the merger order by 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, Depreciationearnings before interest, tax, depreciation and Amortizationamortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 49.4%48.8% at September 30, 20172022, and the EBITDA to interest expense was 5.45.1 to 1.0 for the twelve months ended September 30, 2017.2022.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. At September 30, 2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


Long Term Debt
On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15of each year. The proceeds from the issuance were used for repayment of commercial paper as well as general corporate purposes. For further information, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on Form 10-K for the year ended December 31, 2021.
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Puget Energy
Credit Facility
At September 30, 2017,On May 16, 2022, Puget Energy maintained anentered into a new $800.0 million revolving senior secured credit facility which matures April 2018.to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR is being discontinued in 2023. The proceeds of the PE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The Puget Energy revolving senior secured credit facility also has an accordion feature, which, upon the banks' approval, wouldreceipt of commitments from one or more lenders, could increase the size of the facility up to $1.3 billion.
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'sa prime based rate or LIBOR,SOFR, in either case, 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 September 30, 2017,2022, there was $83.1$93.3 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBORSOFR was 1.75% and the commitment fee was 0.275%.
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a maximum leverage ratio financial covenant as defined inthat requires the agreement governing the senior secured credit facility.ratio of (a) total funded indebtedness to (b) total capitalization to be 65.0% or less at all times. As of September 30, 2017,2022, Puget Energy was in compliance with all applicable covenants.

On September 26, 2022, PE borrowed $50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds will be used for general corporate purposes.
In October 2017,
Shelf Registrations
On March 10, 2022, Puget Energy entered into a new $800.0filed an S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by Puget Energy's assets. As of the date of this report, $550.0 million credit facilitywas available to replace the existing facility.be issued. The terms and conditions, including fees,shelf registration will expire in March 2025.

Long-Term Debt
On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate options, financial covenant,of 2.379%. The notes mature on June 15, 2028, and accordion feature remain substantiallypay interest semi-annually on June 15 and December 15of each year. Proceeds from the same. The new facility maturesissuance of the notes were invested in October 2022. short-term money market funds, and then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.
On May 15, 2017,June 23, 2021, Puget Energy entered into a revolving credit agreement withreceived an equity contribution from Puget LNG, a wholly owned subsidiary ofEquico, LLC, Puget Energy. UnderEnergy’s parent company. The proceeds from the agreement,equity contribution were used to pay off Puget Energy’s $210.0 million term loan on June 23, 2021.
On March 17, 2022, Puget Energy agreed to loan up to $200.0issued $450.0 million to Puget LNG to finance Puget LNG’s portionof senior secured notes at an interest rate of 4.224%. The notes mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15of each year. Proceeds from the issuance of the construction costs of a liquefied natural gas facility located at the Port of Tacoma. The interest rate for amounts borrowed under the agreement is equalnotes were invested in short-term money market funds, and then used to the one month LIBOR rate in effect on the first day of each month plus the applicable marginrepay Puget Energy's $450.0 million 5.625% notes that were originally scheduled to mature July 2022.
On April 28, 2022, Puget Energy would payredeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense.
For further information, see Part II, Item 8, Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's Annual Report on loans under its credit facility. Interest underForm 10-K for the agreement is due on the first business day of each quarter and Puget LNG may elect to make payment in kind (PIK) interest payments in which the interest due is added to the balance outstanding under the agreement. The maximum balance outstanding under the agreement, including PIK interest, is $200.0 million.year ended December 31, 2021.


Dividend Payment Restrictions
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.Commission in 2009.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.63.7 to 1.0 for the twelve months ended September 30, 20172022.
At September 30, 2017,2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


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Other
New Accounting Pronouncements
For the discussion of new accounting pronouncements, see Note 2, "New Accounting Pronouncements" in the Combined Notes to the consolidated financial statementsConsolidated Financial Statements included in Part IItem 1 of this report.


Inflation Reduction Act
On August 16, 2022, the Inflation Reduction Act (IRA) was signed into public law. The IRA is intended to lower gasoline and electricity prices, increase energy security, and help consumers to afford emission-cutting technologies. In addition, the IRA will provide tax credits for clean electricity sources and renewable technologies, such as solar and wind. As of September 30, 2022, the IRA has no material financial impact on the Company, however the Company continues to assess the potential impacts of the legislation.

Washington Clean Energy Transformation Act
In May 2019, Washington State passed the Clean Energy Transformation Act (CETA) that supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The CETA requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean energy implementation plans are required every four years from each investor-owned utility (IOU) and must propose interim targets for meeting the 2045 standard between 2030 and 2045, and describe an actionable plan that the IOU intends to pursue to meet the standard. The Washington Commission may approve, reject or recommend alterations to an IOU’s plan.
In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive-based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those facilities. IOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPAs) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.
IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather-adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.
The law requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time. The Company intends to seek recovery of any costs associated with the clean energy legislation through the regulatory process.

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. On March 6, 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, Districteach of Montana. On July 12, 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 on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. Due to a re-estimate of Colstrip Units 1 and 2 Asset Retirement and Environmental obligation (ARO) costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected bycoal-fired generating units located in Colstrip, Montana. PSE has accelerated the settlement, and allegations in the lawsuit againstdepreciation of Colstrip Units 3 and 4 were dismissedto December 31, 2025 as part of the settlement. While2019 GRC. The 2017 GRC 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 September 2, 2022, PSE has estimatedand Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the AROapplicable held for sale accounting criteria were not met as of September 30, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of September 30, 2022.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington CETA requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

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Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE had accrued $3.2 million for the fine. On March 28, 2017, Pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On JuneMay 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million, of which $1.3 million was suspended. On June 30, 2017, PSE paid the $1.5 million penalty it had accrued previously to a liability reserve account for property damage claims. However, litigation is still pending regarding damage and personal injury claims.




Regional Haze Rule
On January 10, 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however, the end date will remain 2028. Aspects of these revisions are currently being challenged by various entities nationwide and a briefing is scheduled for the end of July 2017. In the meantime, Montana has indicated that they plan to work on and submit a State Implementation Plan for the second planning period.

Coal Combustion Residuals
On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR's) under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.
The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

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. PSE filed comments on this rule in December 2014. The EPA published a final rule on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10, 2017, the EPA proposed to repeal the CPP rule and is currently accepting comment on the proposal. PSE is still reviewing the impact of these developments. However, Washington has moved forward with its own Clean Air Rule (CAR). The potential impacts of the Washington Clean Air Rule are described below.

Washington Clean Air Rule
The CAR was adopted on September 15, 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.
The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.
On September 27, 2016, PSE along with the Colstrip owners, Avista Corporation, Cascade Natural Gas CorporationPacifiCorp and NW Natural,Portland General Electric Company filed a lawsuit against the Montana Attorney General challenging the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. On September 29, 2022, the magistrate judge in the District Court proceeding issued a recommendation to the presiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. On October 18, 2022 the U.S. District Court Judge accepted in full the magistrate judge recommendation for a permanent injunction against enforcement of Senate Bill 266.

Washington Climate Commitment Act
In 2021, the Eastern District of Washington challengingLegislature adopted the CAR. On September 30, 2016, the four companies filedClimate Commitment Act, which establishes a similar challenge to the CAR in Thurston County Superior Court. While awaiting the outcome of the pending litigation, the Company has undertaken steps to comply with the first compliance period of the CAR, which begangreenhouse gases (GHG) emissions cap-and-invest program that will take effect on January 1, 2017.2023. The Washington Department of Ecology is currently developing regulations to implement the program, but in general, the program will require covered entities to obtain emission allowances or offset credits for covered emissions.

The Climate Commitment Act will regulate PSE both as an electric utility and as a natural gas distribution utility. PSE will be required to obtain emission allowances or offset credits for GHG emissions associated with electricity generated or imported into the state if the emissions associated with this generation exceed 25,000 metric tons of carbon dioxide equivalent per year. As an electric utility subject to Washington’s CETA, which is discussed above, PSE will receive some emission allowances at no cost through 2050 to mitigate impacts to ratepayers. PSE will also be required to obtain emission allowances for GHG emissions associated with natural gas supplied to customers, and will receive some emission allowances at no cost on a declining basis to mitigate rate impacts to certain customers. The Department of Ecology’s implementing regulations were finalized on September 29, 2022 and are effective on October 30, 2022.

Related Party Transactions
In August 2015, PSE filed a proposal with the Washington Commission to develop a 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.

Currently under construction,On February 1, 2022, the Tacoma LNG facility is expected to be operationalat the Port of Tacoma completed commissioning and commenced commercial operations in 2019.February 2022. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. AsPer this allocation of September 30, 2017, Puget LNG has incurred $86.5costs, $245.3 million in construction work in progressof non-utility plant and $7.8 million of operating costs related to Puget LNG’sLNG's portion of the Tacoma LNG facility.facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of September 30, 2022. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.



Integrated Resource Plans, Resource Acquisition and Development
On April 1, 2021, the Company filed the final 2021 Integrated Resource Plan and the 2021 Request for Proposals for All Resources (All-source RFP), and has since received a number of bids, which the Company is currently evaluating. Bidders have informed the Company that prices are being impacted by substantial inflationary pressure, resulting in higher proposed prices for energy than anticipated. While the current estimates related to RFP bids have no direct financial impact, the Company continues to monitor the impacts of inflation and market pricing pressures on future energy needs.
For further information, see Part I, Item I - “Integrated Resource Plans, Resource Acquisition and Development” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

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

Item 3.     Quantitative and Qualitative Disclosure about Market Risk


The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" ofin the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2021.


Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Risk Management Committee (EMC) 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 September 30, 2017,2022, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.



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Changes in Internal Control over Financial Reporting
There werehave been no changes in Puget Energy'sEnergy’s internal control over financial reporting that occurred during the period covered by this quarterly reportquarter ended September 30, 2022 that have materially affected, or are reasonably likely to materially affect, itsPuget 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 September 30, 2017,2022, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.


Changes in Internal Control over Financial Reporting
There werehave been no changes in Puget Sound Energy'sPSE’s internal control over financial reporting that occurred during the period covered by this quarterly reportquarter ended September 30, 2022 that have materially affected, or are reasonably likely to materially affect, itsPSE’s internal control over financial reporting.
In January 2017, Puget Sound Energy implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The new/updated systems were used in preparing financial information for the nine months ended September 30, 2017. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes were being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.

PART II            OTHER INFORMATION


Item 1.         Legal Proceedings


Contingencies arising out of the Company's normal course of business existed as of September 30, 2017.2022.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitment"Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements included in Part I.Item 1 of this report.

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


Item 1A.     Risk Factors


There have been no material changes from the risk factors set forth in Part I, Item 1A, "Risk Factors" ofin the Company's Annual Report on Form 10-K for the periodyear ended December 31, 2016.2021. Although the Company has not been materially affected, the following represents an ongoing risk that the Company continues to monitor.


Item 5.                      Other Information

DeparturePSE could be adversely affected by disruptions in the global economy and rising geopolitical tensions caused by the ongoing military conflict between Russia and Ukraine.The global economy has been negatively impacted by the military conflict between Russia and Ukraine. Governments including the U.S., United Kingdom, and European Union imposed import and export controls on certain products and economic sanctions on certain industries and parties in Russia. Further escalation of Directors and Certain Officers; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

On November 2, 2017, the Boards of Directors (collectively, the “Board”) of Puget Energy, Inc. (“Puget Energy”) and its wholly owned subsidiary, Puget Sound Energy, Inc. (“PSE” and together with Puget Energy, the “Company”) ratified the appointment of Stephen King to serve as Controller, which role he has held since August 28, 2017 and the Board further approved his appointment as Principal Accounting Officer, effective November 2, 2017.
On November 2, 2017, Mr. King replaces Matthew Marcelia, who the Board appointed to serve as Director, Tax, with the same effective date of November 2, 2017.

Prior to holding his current positions, Mr. King, 33, was a Senior Manager at PricewaterhouseCoopers LLP, a national public accounting firm, since September 2007 where he audited utility, technology and telecommunication companies. Mr. King received a Bachelor’s degree in Accounting and Finance from Ohio University.
No new agreement will be entered into in connection with Mr. King’s appointmentgeopolitical tensions related to the position of Controllermilitary conflict, including increased trade barriers or restrictions on global trade, could result in, among other things, cyberattacks, supply chain disruptions, and Principal Accounting Officer,increased costs, including energy costs, which may adversely affect our business and insupply chain. In addition, to his current compensation package, Mr. King will participate in the Company’s Long Term Incentive Plan and other benefit programseffects of the Company.

Also effective November 2, 2017, the sole shareholderongoing conflict could heighten many of Puget Energy appointed and elected Scott Armstrong, who is currently on the Board of Directors of PSE, to the Board of Directors of Puget Energy. Mr. Armstrong will continue to serve on the Governance, Compensation and Asset Management Committees of each of the Companies.

Also effective November 2, 2017, the sole shareholder of PSE appointed and elected Barbara Gordon to the Board of Directors of PSE. Initially, Ms. Gordon will not be appointed to any committees of the Board.
Ms. Gordon was most recently the Executive Vice President and Chief Customer Officer of Apptio, which position she held from 2016 through 2017, when she retired. Prior to her service at Apptio, she served as Senior Vice President and Chief Operating Officer at Isilon/EMC from 2013 to 2016 and as Corporate Vice President, Worldwide Customer Service and Support at Microsoft from 2003 to 2013. Ms. Gordon also currently serves as Vice President on the Board of Directors for the Seattle-King County Habitat for Humanity and chairs their Strategy Committee.
The compensation offered to Ms. Gordon for her service as a director of PSE will be the same as that offered to all non-employee independent board members of the Company, pursuant to the director compensation schedule filed as Exhibit 10.38 toour known risks described in Part I, Item 1A, "Risk Factors" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015.2021.




Item 6.         Exhibits


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

71




EXHIBIT INDEX

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).
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).
Amended and Restated Bylaws of Puget Energy, dated February 6, 2009 (incorporatedInc. (Incorporated herein by reference to Exhibit 3.3 to Puget Energy’sEnergy's Current Report on Form 8-K,10-K, dated February 25, 2022, Commission File No. 1-16305)001-16305).
Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated(Incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’sEnergy's Current Report on Form 10-K dated February 25, 2022, Commission File No. 001-04393).
Seventh Supplemental Indenture dated March 17, 2022 relating to Puget Energy's 4.224% Senior Secured Notes due 2032 (incorporated herein by reference to Exhibit 4.1 Puget Energy's Current Report on Form 8-K, filed March 18 2022, Commission File No. 1-4393).1-1605.)
Second Amended and Restated Credit Agreement dated October 25, 2017May 16, 2022 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.1 to Puget Energy's Current Report on Form 8-K, filed in October 31, 2017, Commission File No. 1-16305).
Amended and Restated Credit Agreement dated October 25, 2017May 16, 2022 among Puget Sound Energy Inc., as Borrower, Mizuho Bank, Ltd.LTD., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2017, Commission file No. 1-4393).
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016 and 12 months end September 30, 2017).
12.2*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2012 through 2016 and 12 months ended September 30, 2017).
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.
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.
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.
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.
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.
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 September 30, 20172022 filed on November 3, 20172, 2022 formatted in Inline 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), (v) the Consolidated Statements of Common Shareholder's Equity (Unaudited), and (v)(vi) the Notes to Consolidated Financial Statements (submitted electronically herewith)
104Cover Page Interactive Data File (embedded within the Inline XBRL document).
__________________
*
Filed herewith.

*Filed herewith.



72


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:  November 3, 20172, 2022



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