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, 20172021
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-20210930_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-20210930_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.
5
6
7
9
10
Puget Sound Energy, Inc.
12
612
713
8
Puget Sound Energy, Inc.
Consolidated Statements of Income – Three and Nine Months Ended September 30, 2017 and 2016
9
Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2017 and 2016
10
Consolidated Balance Sheets – September 30, 20172021, and December 31, 20162020
1115
1316
Notes
1417
3536
5365
5366
5467
5467
5467
Item 5.Other Information
54
5567
Exhibit Index
56
Signatures
57


DEFINITIONS

AROAsset Retirement and Environmental Obligations
ASU
68
69

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) or other related federal initiatives;
●PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
●The ability to restart generation following a regional transmission disruption;
●The ability of a natural gas or electric plant to operate as intended;
●Changes in climate, or weather conditions, 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; absences due to pandemics, accidents, natural disasters or other significant, unforeseeable events; availability of qualified employees or the loss of a key executive;
●The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;
●The ability to maintain effective internal controls over financial reporting and operational processes;
●Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally; and
●Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.thereunder; and
●Recent laws proposed or passed by various municipalities in PSE's service territory, including Seattle, seek to reduce or eliminate the use of natural gas in various contexts, such as for space, cooking, and water heating in new commercial and multifamily buildings. Such laws may impact operations due to costs and delays from incremental permitting and other requirements that are outside PSE's control.


Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  For further information, see Item 1A, “Risk Factors” in the Company's most recent Annual Report on Form 10-K.10-K for the year ended December 31, 2020.



4

PART I                    FINANCIAL INFORMATION


Item 1.                      Financial Statements


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





Three Months Ended
September 30,		Nine Months Ended
September 30,
2021202020212020
Operating revenue:
Electric$613,386 $500,976 $1,935,800 $1,638,432 
Natural Gas122,808 112,357710,838 660,997
Other34,042 7,09353,074 18,806
Total operating revenue770,236 620,426 2,699,712 2,318,235 
Operating expenses:
Energy costs:
Purchased electricity190,928 115,631558,853 406,860
Electric generation fuel92,883 54,282209,749 150,880
Residential exchange(16,491)(16,121)(59,885)(56,922)
Purchased natural gas35,518 31,229253,362 247,362
Unrealized (gain) loss on derivative instruments, net(88,517)(39,942)(172,795)(3,563)
Utility operations and maintenance143,873 141,032454,580 444,074
Non-utility expense and other24,440 6,34043,912 35,143
Depreciation & Amortization162,743 161,209537,104 462,890
Conservation amortization19,234 21,29575,195 69,009
Taxes other than income taxes68,471 62,163255,618 236,460
Total operating expenses633,082 537,118 2,155,693 1,992,193 
Operating income (loss)137,154 83,308 544,019 326,042 
Other income (expense):
Other income14,626 13,05042,746 43,685
Other expense(3,317)(2,160)(7,177)(12,910)
Interest charges:
AFUDC4,337 3,84711,698 11,404
Interest expense(84,769)(88,608)(264,536)(284,285)
Income (loss) before income taxes68,031 9,437 326,750 83,936 
Income tax (benefit) expense18,462 (559)32,946 2,237
Net income (loss)$49,569 $9,996 $293,804 $81,699 
 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,
 2021202020212020
Net income (loss)$49,569 $9,996 $293,804 $81,699 
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $427, $291, $1,695 and $2,097, respectively1,608 1,090 6,379 7,890 
Other comprehensive income (loss)1,608 1,090 6,379 7,890 
Comprehensive income (loss)$51,177 $11,086 $300,183 $89,589 
 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,
2021		December 31, 2020
Utility plant (at original cost, including construction work in progress of $875,382 and $712,204 respectively):
Electric plant$9,577,534 $9,200,231 
Natural gas plant4,433,625 4,227,532 
Common plant1,081,770 1,116,524 
Less: Accumulated depreciation and amortization(3,930,396)(3,671,094)
Net utility plant11,162,533 10,873,193 
Other property and investments:
Goodwill1,656,513 1,656,513 
Other property and investments318,611 324,184 
Total other property and investments1,975,124 1,980,697 
Current assets:
Cash and cash equivalents104,666 52,307 
Restricted cash11,362 29,544 
Accounts receivable, net of allowance for doubtful accounts of $37,776 and $20,080, respectively320,830 352,132 
Unbilled revenue151,364 221,871 
Materials and supplies, at average cost119,763 118,333 
Fuel and natural gas inventory, at average cost67,019 48,795 
Unrealized gain on derivative instruments306,685 33,015 
Prepaid expense and other68,275 45,746 
Power contract acquisition adjustment gain17,213 14,874 
Total current assets1,167,177 916,617 
Other long-term and regulatory assets:
Power cost adjustment mechanism74,298 82,801 
Purchased gas adjustment receivable56,268 87,655 
Regulatory assets related to power contracts9,996 11,728 
Other regulatory assets814,015 747,651 
Unrealized gain on derivative instruments55,842 8,805 
Power contract acquisition adjustment gain67,309 80,900 
Operating lease right-of-use asset187,903 172,167 
Other93,756 80,751 
Total other long-term and regulatory assets1,359,387 1,272,458 
Total assets$15,664,221 $15,042,965 

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




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



CAPITALIZATION AND LIABILITIES
September 30,
2021		December 31, 2020
Capitalization
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding$— $— 
Additional paid-in capital3,523,532 3,313,532 
Retained earnings1,138,524 912,787 
Accumulated other comprehensive income (loss), net of tax(80,058)(86,437)
Total common shareholder’s equity4,581,998 4,139,882 
Long-term debt:
First mortgage bonds and senior notes4,662,000 4,212,000 
Pollution control bonds161,860 161,860 
Long-term debt1,583,000 1,724,700 
Debt discount issuance costs and other(206,061)(206,120)
Total long-term debt6,200,799 5,892,440 
Total capitalization10,782,797 10,032,322 
Current liabilities:
Accounts payable348,786 342,404 
Short-term debt— 373,800 
Current maturities of long-term debt450,000 526,412 
Accrued expenses:
Taxes115,174 110,752 
Salaries and wages37,288 42,530 
Interest80,602 73,647 
Unrealized loss on derivative instruments50,447 31,441 
Power contract acquisition adjustment loss1,817 2,039 
Operating lease liabilities19,646 19,204 
Other69,739 73,385 
Total current liabilities1,173,499 1,595,614 
Other long-term and regulatory liabilities:
Deferred income taxes914,749 810,729 
Unrealized loss on derivative instruments12,007 29,833 
Regulatory liabilities924,654 732,498 
Regulatory liability for deferred income taxes889,045 953,274 
Regulatory liabilities related to power contracts84,522 95,774 
Power contract acquisition adjustment loss8,179 9,689 
Operating lease liabilities176,245 160,980 
Other deferred credits698,524 622,252 
Total long-term and regulatory liabilities3,707,925 3,415,029 
Commitments and contingencies (Note 8)00
Total capitalization and liabilities$15,664,221 $15,042,965 

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

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)
Common StockAdditional Paid-in CapitalAccumulated Other Comprehensive Income (Loss)
SharesAmountRetained EarningsTotal Equity
Balance at December 31, 2019200$— $3,308,957 $775,491 $(84,149)$4,000,299 
Net income (loss)———94,936 — 94,936 
Common stock dividend paid———(22,645)— (22,645)
Other comprehensive income (loss)———— 5,170 5,170 
Balance at March 31, 2020200$— $3,308,957 $847,782 $(78,979)$4,077,760 
Net income (loss)———(23,233)— (23,233)
Common stock dividend paid———(22,419)— (22,419)
Other comprehensive Income (loss)———— 1,630 1,630 
Balance at June 30, 2020200$— $3,308,957 $802,130 $(77,349)$4,033,738 
Net Income (loss)———9,996 — 9,996 
Common stock dividend paid———(348)— (348)
Other comprehensive income (loss)———— 1,090 1,090 
Balance at September 30, 2020200$— $3,308,957 $811,778 $(76,259)$4,044,476 
Balance at December 31, 2020200$— $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)$4,552,735 
Net income (loss)———49,569 —49,569 
Common stock dividend paid———(21,914)—(21,914)
Other comprehensive income (loss)————1,608 1,608 
Balance at September 30, 2021200$— $3,523,532 $1,138,524 $(80,058)$4,581,998 

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,
20212020
Operating activities:
Net Income (loss)$293,804 $81,699 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization537,104 462,890 
Conservation amortization75,195 69,009 
Deferred income taxes and tax credits, net38,095 (1,922)
Net unrealized (gain) loss on derivative instruments(172,795)(3,563)
(Gain) or loss on extinguishment of debt— 13,546 
AFUDC - equity(19,269)(17,772)
Production tax credit utilization(45,562)(17,558)
Other non-cash(13,437)5,466 
Funding of pension liability(18,000)(18,000)
Regulatory assets and liabilities(87,076)(90,513)
Purchased gas adjustment31,387 30,859 
Other long term assets and liabilities552 (17,094)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue101,809 188,053 
Materials and supplies(1,430)(4,365)
Fuel and natural gas inventory(18,224)(4,290)
Prepayments and other(22,529)(18,912)
Accounts payable(5,754)(26,068)
Taxes payable4,422 9,461 
Other(7,161)(25,086)
Net cash provided by (used in) operating activities671,131 615,840 
Investing activities:
Construction expenditures - excluding equity AFUDC(662,189)(678,085)
Other1,076 (925)
Net cash provided by (used in) investing activities(661,113)(679,010)
Financing activities:
Change in short-term debt, net(373,800)45,000 
Dividends paid(68,067)(45,412)
Investment from Parent210,000 — 
Proceeds from long-term debt and bonds issued961,238 644,690 
Redemption of bonds and notes(502,414)(450,000)
Repayment of term loan and revolving credit(234,000)(150,200)
Other31,202 (2,525)
Net cash provided by (used in) financing activities24,159 41,553 
Net increase (decrease) in cash, cash equivalents, and restricted cash34,177 (21,617)
Cash, cash equivalents, and restricted cash at beginning of period81,851 66,146 
Cash, cash equivalents, and restricted cash at end of period$116,028 $44,529 
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$237,348 $245,183 
Cash payments (refunds) for income taxes16,861 3,820 
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$69,909 $67,321 
Recognition of finance lease eliminated from cash flows44,347 — 

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,
2021202020212020
Operating revenue:
Electric$613,386 $500,976 $1,935,800 $1,638,432 
Natural Gas122,808 112,357 710,838 660,997 
Other34,042 7,093 53,074 18,806 
Total operating revenue770,236 620,426 2,699,712 2,318,235 
Operating expenses:
Energy costs:
Purchased electricity190,928 115,631 558,853 406,860 
Electric generation fuel92,883 54,282 209,749 150,880 
Residential exchange(16,491)(16,121)(59,885)(56,922)
Purchased natural gas35,518 31,229 253,362 247,362 
Unrealized (gain) loss on derivative instruments, net(88,517)(39,942)(172,795)(3,563)
Utility operations and maintenance143,873 141,032 454,580 444,074 
Non-utility expense and other23,920 5,510 42,290 33,293 
Depreciation & Amortization162,629 161,155 536,794 462,742 
Conservation amortization19,234 21,295 75,195 69,009 
Taxes other than income taxes68,471 62,163 255,618 236,460 
Total operating expenses632,448 536,234 2,153,761 1,990,195 
Operating income (loss)137,788 84,192 545,951 328,040 
Other income (expense):
Other income11,937 10,424 34,398 34,569 
Other expense(3,317)(2,160)(7,177)(12,910)
Interest charges:
AFUDC4,337 3,847 11,698 11,404 
Interest expense(57,718)(61,592)(182,958)(184,770)
Income (loss) before income taxes93,027 34,711 401,912 176,333 
Income tax (benefit) expense18,902 1,649 49,953 16,913 
Net income (loss)$74,125 $33,062 $351,959 $159,420 

 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,
 2021202020212020
Net income (loss)$74,125 $33,062 $351,959 $159,420 
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,000, $853, $3,369 and $3,925, respectively3,757 3,195 12,674 14,765 
Amortization of treasury interest rate swaps to earnings, net of tax of $25, $26, $77, and $77, respectively97 97 289 289 
Other comprehensive income (loss)3,854 3,292 12,963 15,054 
Comprehensive income (loss)$77,979 $36,354 $364,922 $174,474 
 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,
2021		December 31, 2020
Utility plant (at original cost, including construction work in progress of $875,382 and $712,204, respectively):
Electric plant$11,393,548 $11,035,402 
Natural Gas plant4,990,626 4,786,419 
Common plant1,104,047 1,139,120 
Less:  Accumulated depreciation and amortization(6,325,688)(6,087,748)
Net utility plant11,162,533 10,873,193 
Other property and investments:
Other property and investments74,294 83,855 
Total other property and investments74,294 83,855 
Current assets:
Cash and cash equivalents94,286 51,177 
Restricted cash11,362 29,544 
Accounts receivable, net of allowance for doubtful accounts of $37,776 and $20,080, respectively323,594 355,850 
Unbilled revenue151,364 221,871 
Materials and supplies, at average cost119,763 118,333 
Fuel and natural gas inventory, at average cost65,755 47,531 
Unrealized gain on derivative instruments306,685 33,015 
Prepaid expense and other68,275 45,746 
Total current assets1,141,084 903,067 
Other long-term and regulatory assets:
Power cost adjustment mechanism74,298 82,801 
Purchased gas adjustment receivable56,268 87,655 
Other regulatory assets814,015 747,651 
Unrealized gain on derivative instruments55,842 8,805 
Operating lease right-of-use asset187,903 172,167 
Other92,638 79,231 
Total other long-term and regulatory assets1,280,964 1,178,310 
Total assets$13,658,875 $13,038,425 
 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.

12


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




CAPITALIZATION AND LIABILITIES

September 30,
2021		December 31, 2020
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding$859 $859 
Additional paid-in capital3,485,105 3,485,105 
Retained earnings1,057,515 876,401 
Accumulated other comprehensive income (loss), net of tax(167,993)(180,956)
Total common shareholder’s equity4,375,486 4,181,409 
Long-term debt:
First mortgage bonds and senior notes4,662,000 4,212,000 
Pollution control bonds161,860 161,860 
Debt discount, issuance costs and other(39,268)(35,816)
Total long-term debt4,784,592 4,338,044 
Total capitalization9,160,078 8,519,453 
Current liabilities:
Accounts payable358,809 342,504 
Short-term debt— 373,800 
Current maturities of long-term debt— 2,412 
Accrued expenses:
Taxes114,702 107,254 
Salaries and wages37,288 42,530 
Interest58,175 48,189 
Unrealized loss on derivative instruments50,447 31,441 
Operating lease liabilities19,646 19,204 
Other69,739 73,385 
Total current liabilities708,806 1,040,719 
Other long-term and regulatory liabilities:
Deferred income taxes1,093,920 987,382 
Unrealized loss on derivative instruments12,007 29,833 
Regulatory liabilities923,390 731,234 
Regulatory liabilities for deferred income tax889,613 953,987 
Operating lease liabilities176,245 160,980 
Other deferred credits694,816 614,837 
Total long-term and regulatory liabilities3,789,991 3,478,253 
Commitments and contingencies (Note 8)00
Total capitalization and liabilities$13,658,875 $13,038,425 

 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.

13

 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, 201985,903,791$859 $3,485,105 $751,193 $(188,477)$4,048,680 
Net income (loss)—— — 111,321 — 111,321 
Common stock dividend paid—— — (53,794)— (53,794)
Other comprehensive income (loss)—— — — 7,806 7,806 
Balance at March 31, 202085,903,791$859 $3,485,105 $808,720 $(180,671)$4,114,013 
Net income (loss)—— — 15,037 — 15,037 
Common stock dividend paid—— — (46,015)— (46,015)
Other comprehensive income (loss)—— — — 3,956 3,956 
Balance June 30, 202085,903,791$859 $3,485,105 $777,742 $(176,715)$4,086,991 
Net income (loss)—— — 33,062 — 33,062 
Common stock dividend paid—— — (25,742)— (25,742)
Other comprehensive income (loss)—— — — 3,292 3,292 
Balance at September 30, 202085,903,791$859 $3,485,105 $785,062 $(173,423)$4,097,603 
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—— — — 4,555 4,555 
Balance 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— — — — 3,854 3,854 
Balance September 30, 202185,903,791$859 $3,485,105 $1,057,515 $(167,993)$4,375,486 

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


14

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,
20212020
Operating activities:
Net Income (loss)$351,959 $159,420 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization536,794 462,742 
Conservation amortization75,195 69,009 
Deferred income taxes and tax credits, net38,718 7,259 
Net unrealized (gain) loss on derivative instruments(172,795)(3,563)
AFUDC - equity(19,269)(17,772)
Production tax credit utilization(45,562)(17,558)
Other non-cash(21,497)(2,441)
Funding of pension liability(18,000)(18,000)
Regulatory assets and liabilities(87,076)(90,513)
Purchased gas adjustment31,387 30,859 
Other long term assets and liabilities8,516 (8,391)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue102,763 185,957 
Materials and supplies(1,430)(4,365)
Fuel and natural gas inventory(18,224)(4,290)
Prepayments and other(22,529)(18,912)
Accounts payable4,169 (26,038)
Taxes payable7,448 9,542 
Other(4,127)(22,628)
Net cash provided by (used in) operating activities746,440 690,317 
Investing activities:
Construction expenditures - excluding equity AFUDC(654,182)(641,862)
Other1,076 (925)
Net cash provided by (used in) investing activities(653,106)(642,787)
Financing activities:
Change in short-term debt, net(373,800)45,000 
Dividends paid(170,845)(125,551)
Proceeds from long-term debt and bonds issued446,063 — 
Redemption of bonds and notes(2,414)— 
Other32,589 11,921 
Net cash provided by (used in) financing activities(68,407)(68,630)
Net increase (decrease) in cash, cash equivalents, and restricted cash24,927 (21,100)
Cash, cash equivalents, and restricted cash at beginning of period80,721 64,891 
Cash, cash equivalents, and restricted cash at end of period$105,648 $43,791 
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$157,699 $161,083 
Cash payments (refunds) for income taxes28,744 9,259 
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$69,909 $67,321 
Recognition of finance lease eliminated from cash flows44,347 — 

 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.

15



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)




(1)Summary of Consolidation Policy

(1)Summary of Consolidation and Significant Accounting Policy

Basis of Presentation
Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE).Energy. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC, (Puget LNG). Puget LNG was formed on November 29, 2016, andwhich has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that 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)FASB 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, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP)GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.


Allowance for Credit Losses
Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.
The allowance increased during 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.
The following table presents the activity in the allowance for credit losses for accounts receivable for the nine months ended September 30, 2021 and 2020:
Puget Energy and
Puget Sound Energy		Nine Months
Ended September 30,
(Dollars in Thousands)20212020
Allowance for credit losses:
Beginning balance$20,080 $8,294 
Provision for credit loss expense 1
26,424 14,660 
Receivables charged-off(8,728)(9,065)
Total ending allowance balance$37,776 $13,889 
_______________
1 $8.5 million of current period provision was deferred as a cost specific to COVID-19 in 2021. Refer to Note 8 "Commitments and Contingencies" for more information.
16

Tacoma LNG Facility
In August 2015, PSE filed a proposal with the Washington Commission to develop a liquified natural gas (LNG) facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility willis designed to provide peak-shaving services to PSE’s natural gas customers, andcustomers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide LNG as fuel to transportation customers, particularly in the marine market. The TacomaOn January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility is expected to be operationalwould result in 2019. Pursuanta net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Commission’sPollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. A hearing on the appeal before the Washington Pollution Control Hearings Board occurred in April 2021 and a decision is anticipated in late 2021 or early 2022. The facility achieved mechanical completion in February 2021; however, it remains nonoperational as additional construction and testing are still being completed.
Pursuant to an order Puget LNGby the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of thecommon capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0%to Puget LNG, LLC (Puget LNG). Per this allocation of the capitalcosts, $238.8 million and operating costs.
For Puget Energy, $86.4$231.6 million inof 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, 2021 and December 31, 2020, respectively. Additionally, $0.9 million and $0.5 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, 2021, and September 30, 2020, respectively. Further, $232.8 million and $207.7 million of 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, 2021 and December 31, 2020, respectively, as PSE is a regulated entity.


Variable Interest Entities
On April 12, 2017, PSE entered into a power purchase agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) pursuant to which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy certificates (RECs) to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Skookumchuck is a variable interest entity (VIE) and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $12.3 million was recognized in purchased electricity on the Company's consolidated statements of income for the nine months ended September 30, 2021 and $2.6 million is included in accounts payable on the Company's consolidated balance sheet as of September 30, 2021.

(2)  New Accounting Pronouncements


Revenue RecognitionReference Rate Reform
In May 2014,March 2020, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers2020-04, "Reference Rate Reform (Topic 606)"848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020). ASU 2014-092020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related amendments outline a single comprehensive model for use in accounting forto the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of September 30, 2021, the Company has not utilized any of the expedients discussed within this ASU; however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.

17

(3) Revenue

The following table presents disaggregated revenue arising from contracts with customers, and supersedes most currentother revenue recognition guidance, including industry-specific guidance. The Accounting Standards Update (ASU)by major source:
Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Three Months Ended
September 30,		Nine Months Ended
September 30,
Revenue from contracts with customers:2021202020212020
Electric retail$508,476 $458,573 $1,680,290 $1,499,378 
Natural gas retail115,460 103,486 681,680 637,239 
Other141,128 46,111 278,911 125,227 
Total revenue from contracts with customers765,064 608,170 2,640,881 2,261,844 
Alternative revenue programs(13,539)2,189 (19,488)23,089 
Other non-customer revenue18,711 10,067 78,319 33,302 
Total operating revenue$770,236 $620,426 $2,699,712 $2,318,235 

Revenue at PSE is based onrecognized when performance obligations under the principle that an entity should recognize revenue to depict theterms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of goods or services to customers in ancontrol of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount that reflects theof consideration to which the entity expectsexpected to be entitledreceived in exchange for thosetransferring goods orand services.  The ASU also requires additional disclosure about the nature, amount, timing

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

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

Electric Transmission and Natural Gas Transportation Revenue
Transmission and transportation tariff contracts include a change in the presentation of alternative revenue program revenue of the Company's consolidated statement 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'sperformance obligation to make lease payments arising from a lease, measured on a discounted basis;transmit and (ii) a right-of-use asset, whichtransport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is an asset that representsdetermined using the lessee’soutput method. Similar to retail revenue, the Company utilizes the right to use, or controlinvoice practical expedient as PSE’s right to consideration is tied directly to the usevalue of a specified asset for the lease term.power and natural gas transmitted and transported each month. The income statement recognition is similar to existing lease accounting andprice is based on lease classification. Under the new guidance, lessor accountingtariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.

18

Biogas
Biogas is largely unchanged.a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.
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
Wholesale
Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the adoptionperformance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the new standard.  established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs, as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser.

PWI Land Sale
On August 13, 2021, Puget Western, Inc. (PWI) a wholly-owned subsidiary of Puget Sound Energy sold a parcel of land that resulted in $23.2 million of other revenue from contracts with customers. PWI purchases, develops, and sells land holdings throughout PSE’s service territory, thus, the sale was reported as non-utility revenue of $23.2 million and non-utility expense of $12.9 million.

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

Transaction Price Allocated to Remaining Performance Obligations
In December 2020, Puget LNG entered into a contract with one customer where Puget LNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods:
Puget Energy
(Dollars in Thousands)20242025202620272028ThereafterTotal
Remaining Performance Obligations$15,359 $19,710 $19,454 $19,454 $19,454 $102,135 $195,566 

The Company will adopt ASU 2016-02 duringhas elected the first quarter of fiscal year 2019 and expectsoptional exemption in ASC 606, under which 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 anticipatedisclose the new guidance will havetransaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a material impact on the consolidated statementwholly unsatisfied performance obligation. The primary sources of cash flows.

Definitionvariability are (a) fluctuations in market index prices 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 testnatural gas used to determine when a setaspects of acquired assets is not a business. The test requiresvariable pricing and (b) variation in volumes that when substantially allmay be delivered to the customer. Both sources 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 needvariability are expected to be further evaluated. This ASU affects all companies and other reporting organizations that must determine whether they have acquiredresolved at or soldshortly before delivery of each unit of LNG or natural gas. As each unit of LNG or natural gas represents a business. The amendmentsseparate performance obligation, future volumes are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.wholly unsatisfied.


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.

19

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, was a credit of $13.8 million for Puget Energy and $3.5 million for PSE.  The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

(3)(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)., which is described below. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible,feasible; thus, reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy, which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.
PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of September 30, 2017, the Company did not have any outstanding interest rate swap instruments.

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, 2021December 31, 2020
(Dollars in Thousands)Volumes (millions)
Assets1
Liabilities2
Volumes
Assets1
Liabilities2
Electric portfolio derivatives*$193,765 $45,349 *$22,544 $46,922 
Natural gas derivatives (MMBtus)3
315168,762 17,105 32019,276 14,352 
Total derivative contracts$362,527 $62,454 $41,820 $61,274 
Current$306,685 $50,447 $33,015 $31,441 
Long-term55,842 12,007 8,805 29,833 
Total derivative contracts$362,527 $62,454 $41,820 $61,274 
_______________
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 208.4 million One Million British Thermal Units (MMBtu) and purchased electricity of
8.1 million Megawatt Hours (MWhs) at September 30, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 4,5, "Fair Value Measurements"Measurements," to the consolidated financial statements.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, 2021
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$362,527 $— $362,527 $(48,450)$— $314,077 
Liabilities:
Energy derivative contracts$62,454 $— $62,454 $(48,450)$(62)$13,942 
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, 2020
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$41,820 $— $41,820 $(21,696)$— $20,124 
Liabilities:         Liabilities:
Energy derivative contracts60,430
 —
 60,430
 (42,858)—
 17,572
Energy derivative contracts$61,274 $— $61,274 $(21,696)$(9,343)$30,235 
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 netting 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)Classification2021202020212020
Gas for Power Derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net$42,552 $29,940 $95,421 $24,950 
RealizedElectric generation fuel29,404 358 40,502 911 
Power Derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net45,965 10,002 77,374 (21,386)
RealizedPurchased electricity(3,884)3,579 (10,900)(8,584)
Total gain (loss) recognized in income on derivatives$114,037 $43,879 $202,397 $(4,109)
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, 2017,2021, approximately 98.5%99.4% 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%0.6% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.
The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. 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 NGX exchange 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, 2017,2021, PSE had cashdid not have any posted as collateral of $1.4 million related to contracts executed on thisthe ICE platform. As additional contracts are executed on this exchange, the amountAlso, as of September 30, 2021, PSE had $2.0 million in cash posted as collateral to be posted will increase, subject to PSE’s established limit. PSE also hasand a $1.0$1.0 million letter of credit posted as

collateral as a condition of transacting on a physical energy exchange and clearing house in Canada.the ICE NGX platform. 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, 2021.

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, 2021At December 31, 2020
Fair Value1
PostedContingent
Fair Value1
PostedContingent
Contingent FeatureLiabilityCollateralCollateralLiabilityCollateralCollateral
Credit rating2
$7,145 $— $7,145 $26,966 $— $26,966 
Requested credit for adequate assurance6,056 — — 6,576 — — 
Forward value of contract3
62 1,993 N/A9,343 20,903 N/A
Total$13,263 $1,993 $7,145 $42,885 $20,903 $26,966 
_______________
1
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
2
Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3
Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

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

(5) Fair Value Measurements

ASC 820, "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 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.
23

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 $53.1 million and $49.1$52.7 million at September 30, 20172021 and December 31, 2016,2020 respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
The fair value of the 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, 2021December 31, 2020
(Dollars in Thousands)LevelCarrying
Value		Fair
Value		Carrying
Value		Fair
Value
Liabilities:
Long-term debt (fixed-rate), net of discount1
2$6,167,799 $7,810,416 $5,667,740 $7,755,946 
Long-term debt (variable-rate)233,000 33,000 224,700 224,700 
Total liabilities$6,200,799 $7,843,416 $5,892,440 $7,980,646 
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, 2021December 31, 2020
(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$4,784,592 $6,159,385 $4,338,044 $6,086,358 
Total liabilities $3,749,229
 $4,711,358
 $3,747,298
 $4,571,044
Total liabilities$4,784,592 $6,159,385 $4,338,044 $6,086,358 
_______________
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 $22.8 million and $22.7 million for September 30, 2021 and December 31, 2020, respectively, which are not included in fair value.

2 The carrying value includes debt issuances costs of $22.8 million and $22.9 million for September 30, 2021 and December 31, 2020, respectively, which are not included in fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
Puget Energy and
Puget Sound Energy		Fair Value
At September 30, 2021		Fair Value
At December 31, 2020
(Dollars in Thousands)Level 2Level 3TotalLevel 2Level 3Total
Assets:      
Electric derivative instruments$178,003 $15,762 $193,765 $21,947 $597 $22,544 
Natural gas derivative instruments168,690 72 168,762 19,139 137 19,276 
Total assets$346,693 $15,834 $362,527 $41,086 $734 $41,820 
Liabilities:      
Electric derivative instruments$41,015 $4,334 $45,349 $22,607 $24,315 $46,922 
Natural gas derivative instruments15,349 1,756 17,105 13,080 1,272 14,352 
Total liabilities$56,364 $6,090 $62,454 $35,687 $25,587 $61,274 


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 presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
Puget Energy and
Puget Sound Energy		Three Months Ended September 30,
(Dollars in Thousands)20212020
Level 3 Roll-Forward Net Asset/(Liability)ElectricNatural GasTotalElectricNatural GasTotal
Balance at beginning of period$(6,348)$(1,862)$(8,210)$(28,609)$342 $(28,267)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1
20,510 — 20,510 5,516 — 5,516 
Included in regulatory assets / liabilities— (6)(6)— (471)(471)
Settlements(2,734)184 (2,550)846 (347)499 
Transferred into Level 3— — — — — — 
Transferred out of Level 3— — — — — — 
Balance at end of period$11,428 $(1,684)$9,744 $(22,247)$(476)$(22,723)
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)

______________
Puget Energy and
Puget Sound Energy		Nine Months Ended September 30,
(Dollars in Thousands)20212020
Level 3 Roll-Forward Net Asset/(Liability)ElectricNatural GasTotalElectricNatural GasTotal
Balance at beginning of period$(23,718)$(1,135)(24,853)$(3,378)$1,282 $(2,096)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings2
36,020 — 36,020 (21,321)— (21,321)
Included in regulatory assets / liabilities— (1,055)(1,055)— (187)(187)
Settlements(874)506 (368)2,452 (1,571)881 
Transferred into Level 3— — — 0— — 
Transferred out of Level 3— — — — — — 
Balance at end of period$11,428 $(1,684)$9,744 $(22,247)$(476)$(22,723)
1
_______________
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 $20.1 million and $4.8 million for three months ended September 30, 2021 and 2020, 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:$33.2 million and $(19.0) million for nine months ended September 30, 2021 and 2020, 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
2021:
Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$15,762$4,334Discounted cash flowPower prices (per MWh)$34.50 $95.61 $53.50 
Natural gas$72$1,756Discounted cash flowNatural gas prices (per MMBtu)$2.96 $7.45 $5.66 
_______________
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, 2016:2020:
Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$597 $24,315 Discounted cash flowPower prices (per MWh)$22.82 $41.66 $31.54 
Natural gas$137 $1,272 Discounted cash flowNatural gas prices (per MMBtu)$1.89 $3.42 $2.47 
___________
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, 20172021, and December 31, 2016,2020, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.7$8.4 million and $0.2$5.5 million, respectively.


Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for 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, 2017,2021, 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, "Business Combinations".

26

The following table presents the impairmentsimpairment recorded to the Company's intangible asset contracts in 2020, with corresponding reductions to the regulatory liability:
Puget Energy
(Dollars in Thousands)
Valuation DateContract NameCarrying ValueFair ValueWrite Down
March 31, 2020Rocky Reach$147,168$94,603$52,565
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. The unobservable input averages disclosed below represent the arithmetic average of the inputs and are not weighted by volume. A less significant input is the discount rate reflective of PSE'sa market participant's cost of capital used in the valuation.
The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase
contracts' fair value:
Puget Energy
Valuation DateUnobservable InputLowHighAverage
March 31, 2020Power prices (per MWh)$10.23$38.84$24.43
Power contract costs per quarter (in thousands)$6,308$7,085$6,468



(6) Retirement Benefits
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



(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 pay creditsemployer contributions of 4%4.0% of eligible play 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 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.
The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy records purchase accounting adjustments associated withwhile all non-service cost components are included in other income.
For further information, see Note 13, "Retirement Benefits" to the re-measurementconsolidated financial statements included in Item 8 of the retirement plans.Company's Form 10-K for the period ended December 31, 2020.


27

The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 20172021 and 2016:2020:
Puget EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended September 30,
(Dollars in Thousands)202120202021202020212020
Components of net periodic benefit cost:
Service cost$6,722 $6,084 $115 $176 $34 $47 
Interest cost5,595 6,295 293 362 72 92 
Expected return on plan assets(12,060)(12,476)— — (84)(97)
Amortization of prior service cost(476)(393)87 87 2 — 
Amortization of net loss (gain)2,951 2,040 588 512 (10)(20)
Net periodic benefit cost$2,732 $1,550 $1,083 $1,137 $14 $22 

Puget EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Nine Months Ended September 30,
(Dollars in Thousands)202120202021202020212020
Components of net periodic benefit cost:
Service cost$20,166 $18,253 $344 $580 $117 $142 
Interest cost16,786 18,885 879 1,102 226 276 
Expected return on plan assets(36,179)(37,427)— — (266)(292)
Amortization of prior service cost(1,428)(1,180)262 262 5 — 
Amortization of net loss (gain)8,852 6,120 1,763 1,610 (30)(61)
Net periodic benefit cost$8,197 $4,651 $3,248 $3,554 $52 $65 

Puget Sound EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended September 30,
(Dollars in Thousands)202120202021202020212020
Components of net periodic benefit cost:
Service cost$6,722 $6,084 $115 $176 $34 $47 
Interest cost5,595 6,295 293 362 72 92 
Expected return on plan assets(12,061)(12,478)— — (84)(97)
Amortization of prior service cost(378)(393)87 87 2 — 
Amortization of net loss (gain)5,465 4,761 635 575 (11)(34)
Net periodic benefit cost$5,343 $4,269 $1,130 $1,200 $13 $8 

28

Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
Puget Sound EnergyPuget Sound 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)202120202021202020212020
Components of net periodic benefit cost:           Components of net periodic benefit cost:
Service cost$5,020
 $4,976
 $228
 $271
 $18
 $21
Service cost$20,166 $18,253 $344 $580 $117 $142 
Interest cost7,093
 7,064
 571
 581
 125
 88
Interest cost16,786 18,885 879 1,102 226 276 
Expected return on plan assets(11,945) (11,589) —
 —
 (115) (112)Expected return on plan assets(36,182)(37,433)— — (266)(292)
Amortization of prior service cost(495) (495) 11
 11
 —
 —
Amortization of prior service cost(1,135)(1,180)262 262 5 — 
Amortization of net loss (gain)—
 —
 269
 228
 (101) (233)Amortization of net loss (gain)16,396 14,283 1,906 1,810 (40)(103)
Net periodic benefit cost$(327) $(44) $1,079
 $1,091
 $(73) $(236)Net periodic benefit cost$16,031 $12,808 $3,391 $3,754 $42 $23 

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, 20172021 and December 31, 2016:2020:
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,
2021		December 31,
2020		September 30,
2021		December 31,
2020		September 30,
2021		December 31,
2020
Change in benefit obligation:
Benefit obligation at beginning of period$849,383$774,305$46,742$63,000$12,114$11,627
Amendments—————44
Service cost20,16624,337 344756117190
Interest cost16,78625,180 8791,464226368
Actuarial loss (gain)4,58069,413 (630)3,663(80)604
Benefits paid(37,807)(42,775)(1,485)(22,141)(669)(906)
Medicare part D subsidy received—— ——195187
Administrative Expense—(1,077)————
Benefit obligation at end of period$853,108$849,383 $45,850$46,742$11,903$12,114
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, 20172021, are expected to be at least $18.0 million, $1.9$6.9 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, 2017,2021, the Company contributed $18.0 million $1.4 million and $0.2$1.5 million to fund the qualified pension plan and the SERP, respectively. During the nine months ended September 30, 2020, the Company contributed $18.0 million and $18.1 million to fund the qualified pension plan and the SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plan, respectively.plans.



(6)
29

(7) Regulation and Rates


2013 ExpeditedPower Cost Only Rate Filing, Decoupling and Centralia DecisionCase
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 25, 2013,2021. On February 2, 2021, PSE supplemented the Washington Commission issued final orders resolvingPCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%).
On March 2, 2021, the amended decoupling petition, the expedited rate filing (ERF) and the Petition for Reconsideration (relatedparties to the TransAlta Centralia power purchase agreement)PCORC reached an unopposed multiparty settlement in principle. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. Order No.7 in the ERF/decoupling proceeding approved PSE's ERF filing with 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 excessA term 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 costssettlement requires PSE 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'sinclude in its next general rate case (GRC) which was(or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed January 13, 2017, as discussed below. Ina compliance filing with the rate plan, increases are subjectWashington Commission with a revenue increase of $70.9 million or 3.3% due to a cap of 3.0% of the total revenue for customers.update on power costs with rates effective July 1, 2021.


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 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 0.05%, and the natural gas increase to $1.3 million, or 0.15%, and became effective October 15, 2020 and October 1, 2020, respectively.
On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the Internal Revenue Service (IRS) normalization and consistency rules. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement was based on operatinga commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission would open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE has requested it be allowed to track and, if appropriate recover, pending the outcome of the IRS ruling.
On July 30, 2021, the IRS issued a PLR to PSE which concludes that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is an impermissible methodology under the IRS normalization and consistency rules. The PLR requires that PSE request the Washington Commission allow adjustments to its rates to bring PSE back into compliance with IRS rules. Accordingly, on August 10, 2021, the Commission notified parties of their intent to modify the final orders to address the IRS ruling in their PLR and provided parties the opportunity to comment before a final determination is made. 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. 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 allowed PSEmaintained adjustments that mitigated the impacts of the rate increases in response to record a monthly adjustmentthe economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to itsapproximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%. In the order the Washington Commission also approved the collection of the revenue differences tracked since the 2019 GRC rates went into effect within Schedule 141X. The annualized overall rate impact for this element is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. To reflect the impact of the PLR, PSE has recorded a regulatory asset and additional revenues of $24.7 million in its operating revenues relatedresults through September 30, 2021.


30

Decoupling Filings
On December 23, 2020, the Washington Commission approved PSE’s filing to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effectsupdate Schedule 142 decoupling amortization rates, with an effective date of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recoveredJanuary 1, 2021, by zeroing out rates still effective past October 15, 2020 on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs,tariff sheet Schedule 142-H, which arewas replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020.As part of this filing, PSE will true up the PCA and PGA mechanisms, are not included inover-collection amounts for 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, 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, 2021, 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 netrevenue deferrals would be collected from customers within 24 months of reductions from excess earnings of $11.9 million for 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 Companyannual 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 also limitedprobable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that $2.0 million of electric deferred revenue would not be collected within 24 months of the annual period; therefore, a reserve adjustment was booked to a 3.0%2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows forperiod; therefore, no reserve adjustment was booked to 2021 natural gas with no impacts to electric:decoupling revenue.
Effective Date Accrued Through
Deferrals not Included in Annual Rate Increases
(Dollars in Millions)
Natural Gas: 
2016$47.4
201528.7

Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on 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 ended September 30, 2017 and 2016, PSE incurred $21.1 million and $15.6 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred to a regulatory asset in 2017 and $6.5 million in 2016.


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, 2017,2021, in its PCA mechanism, PSE under recovered its powerallowable costs by $8.9$49.7 million of which no amount$20.3 million was apportioned to customers.customers and $1.2 million of interest was accrued on the deferred customer balance. This compares to an overunder recovery of powerallowable costs of $1.4$51.5 million for the nine months ended September 30, 20162020, of which no amounts were$21.9 million was apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease incustomers and accrued $1.6 million of interest on the total baseline ratedeferred customer balance.

Power Cost Adjustment Clause Filing
PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. PSE filed to recover the deferred balance in Docket UE-210300, effective December 1, 2021, 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.

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

The following table sets forth conservation rider rate adjustments approved by the Washington Commission andapproved PSE’s request on September 30, 2021. During 2020, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $76.1 million. Under 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, 20170.7% $16.5
May 1, 2016(0.5) (11.7)

Electric Property Tax Tracker Mechanism
The purposeterms of the property tax trackerPCA’s sharing 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 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 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(0.04)% $(0.9)
May 1, 20160.3 5.7

Federal Incentive Tracker Tariff
The federal incentive tracker tariff passes through to customers the benefits associated 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 and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates from prior year
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2018, proposed0.2% $(48.2)
January 1, 20170.3 (51.7)
January 1, 2016(0.2) (57.3)

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) between October 1, 2017 and September 30, 2019.  Rates change bi-annually on October 1.

The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
October 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 allunder-recovered power costs, PSE absorbed $32.1 million of the PCORC proceeding also providesunder-recovered amount, and customers were responsible 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 has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. remaining $44.0 million, or $46.0 million including interest.




31

Purchased Gas Adjustment Mechanism
On September 30, 2016,17, 2021, PSE filed with the Washington Commission proposed November 2021 PGA rates, which are expected to go into effect on November 1, 2021.As part of that filing, PSE requested an update to power costsannual revenue increase of $59.1 million; where PGA rates, under Schedule 95, which was consistent101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million.Those rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.

The following table presents the PGA mechanism balances and activity at September 30, 2021 and December 31, 2020:
 
Puget Sound Energy
(Dollars in Thousands)At September 30,At December 31,
PGA receivable balance and activity20212020
PGA receivable beginning balance$87,655 $132,766 
Actual natural gas costs218,934 314,792 
Allowed PGA recovery(251,633)(363,886)
Interest1,312 3,983 
PGA receivable ending balance$56,268 $87,655 

Get to Zero Depreciation Deferral
On April 10, 2019, PSE filed an accounting petition with the Washington Commission’s Order No. 04Commission, requesting authorization to defer depreciation expense associated with Get to Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. At September 30, 2021 and December 31, 2020, PSE deferred $7.9 million and $2.8 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89%. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the 2014 PCORC,original GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's next GRC. Finally, the final order set the rate at which PSE could defer and requiredrecover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC.

Crisis Affected Customer Assistance Program
On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the joint petition filedCACAP program. The CACAP-1 program successfully distributed over $8.9 million in bill assistance funds to over 15,000 households from its inception in April 2020 through the program end date on September 30, 2020.
On March 9, 2016, seeking28, 2021, the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to postpone$2,500 in bill assistance per year for each qualifying low-income household. The CACAP-2 total program budget is $20.0 million for electric customers and $7.7 million for natural gas customers. Natural gas funds may be used for electric bills if necessary. Customers may apply for CACAP-2 more than once during the 12-month program year of October-September.
On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Low Income Program (PSE HELP). The Supplemental CACAP benefits, for both electric and natural gas residential customers, would be a combined total of PSE’s GRC.$34.5
32

million and be capped at $23.7 million and $10.8 million, respectively. Additionally, the Supplemental CACAP filing proposed to revise the CACAP-2 total program budget to $27.7 million for electric customers (instead of $20.0 million for electric customers and $7.7 million for natural gas customers). The Supplemental CACAP budget for natural gas customers of $10.8 million would be used for both the CACAP-2 program and the Supplemental CACAP program benefits.
The following table sets forthSupplemental CACAP benefits would be available to PSE’s residential customers who have a past due balance on their PSE electric or natural gas service account and who have a total net household income which is at or below 200% of the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenuefederal poverty level guidelines, based on household, as determined by the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
December 1, 2016(1.7)% $(37.3)

Natural Gas Regulation and Rates
Natural Gas Conservation Rider
Company. The natural gas conservation rider collects revenueSupplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to cover$2,500. If 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 adjustmentsSupplemental CACAP proposed filing is approved by the Washington Commission, PSE would apply the Supplemental CACAP benefits to qualifying residential service accounts automatically with an opt-out option. Both CACAP-2 and the corresponding expected annual impact on PSE’s revenue based on the effective dates:Supplemental CACAP would be administered until funds are exhausted.

 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 TrackerStorm Loss Deferral Mechanism
The purposeWashington Commission has defined deferrable weather-related events and provided that costs in excess of the property tax tracker mechanism is to pass through theannual cost of all property taxes incurred by the Company. The mechanism removes property taxes from general rates and includes those coststhreshold may be deferred 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.

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 file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system.
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, 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 transportationqualifying damage costs that exceed or fall shortmeet the modified Institute 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 receivableElectrical 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.
The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2017(3.3)% $(30.8)
November 1, 2016(0.4) (4.1)

(7)Asset Retirement Obligations

The Company has recorded liabilitiesElectronics Engineers outage criteria for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, and natural gas mains where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).
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.
The CCR rule and two new agreements which include a consent decree with the Sierra Club 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 care 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 remediation2021, PSE incurred $29.0 million in weather-related electric transmission and distribution system restoration costs, at Colstripof which $19.0 million and reduced the Colstrip ARO liability by $5.5$0.2 million for Colstrip Units 1was deferred as regulatory assets related to storms that occurred in 2021 and 22020, respectively. This compares to $15.5 million incurred in weather-related electric transmission 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, 2017:2020, of which the Company deferred $5.3 million as regulatory assets related to storms that occurred in 2020. 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 dismissedper the terms of the GRC settlement, to December 31, 2027, which was subsequently updated to December 31, 2025 as part of the settlement. While PSE has estimated2019 GRC. The 2017 GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the ARO forend of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.


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 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 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.

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, 2016,2020, during the nine months ended September 30, 2017,2021, the Company entered into new power supplyElectric Portfolio and serviceElectric Wholesale Market Transaction contracts with estimated payment obligations totaling $729.5$826.5 million through 2028.2042.

For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2020.


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

33

The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions.
Government mandated stay at home orders and private work from home mandates due to COVID-19 have affected electric and gas loads for residential, commercial, and industrial customers. The Company's electric and natural gas loads may continue to be impacted for the remainder of 2021, due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus.
At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to its customers. The Company has flexibility with capital investments and other measures to maintain sufficient liquidity over the next twelve months. The situation remains fluid and future impacts to the Company that are presently unknown or unanticipated may occur. Furthermore, the severity of impact to the Company could increase the longer the global pandemic persists. On September 30, 2021, the Company announced that in order to comply with state and federal vaccine mandates all employees and contingent workers are required to be fully vaccinated against COVID-19 by December 8, 2021. The government vaccination mandate may impact the Company and our vendors' staffing levels, which could affect storm response and the timeliness of our response to customers' inquiries.
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, 2021, PSE deferred $23.9 million specific to COVID-19 net of offsets.

(9)  Leases

Other than the items discussed below, there have been no significant changes regarding the Company's leases as described in Note 9, "Leases" in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.
During the first quarter of 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease right-of-use (ROU) asset and operating lease liabilities of $26.3 million, of which $0.4 million was recorded in current liabilities and $25.9 million was recorded in other long-term and regulatory liabilities.
In June 2021, the Kent service center facility reached substantial completion which triggered lease commencement. The lease has a term of 20 years and is classified as a finance lease. The Company recognized a ROU asset within electric utility plant and a finance lease liability of $45.4 million, of which $1.0 million was recorded in other current liabilities and $44.4 million was recorded in other deferred credits, respectively.

(10) Other

Long-Term Debt
On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, then used to repay the Company’s $500.0 million 6.00% notes that matured on September 1, 2021.
On June 23, 2021, Puget Energy received an equity contribution from Puget Equico LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan.
On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes.
As of September 30, 2021, Puget Energy maintained an $800.0 million credit facility, of which $33.0 million was drawn and outstanding under the facility. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2020.

34

Short-Term Debt
As of September 30, 2021, no amount was drawn under PSE's credit facility and no amount was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2020.

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


The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2016.2020. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.operations, including the COVID-19 pandemic.


Overview


Puget Energy is an energy services holding company and substantially all of its operations are conducted through its 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 LNGliquefied natural gas (LNG) facility currentlywhich is under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board (CPPIB), the British Columbia Investment Management Corporation and(BCIMC), the Alberta Investment Management Corporation.Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. In July 2021, CPPIB entered into an agreement to sell its shares to Macquarie Washington Clean Energy Investment, L.P., and Ontario Teachers’ Pension Plan Board. The sale is conditioned upon the approval of various federal and state agencies, including that of the Washington Commission. Puget Energy and PSE are collectively referred to herein as “the Company.”
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.


COVID-19 Update
The outbreak of the Coronavirus Disease 2019 (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The 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 various stages of continued stay at home orders, work from home mandates, and business disruptions caused by COVID-19, customer usage patterns were impacted, thus affecting the Company's electric and natural gas load. Overall, during
35

the nine months ended September 30, 2021, electric and natural gas loads increased 1.6% and decreased 2.7%, respectively; residential electric and natural gas loads increased 5.9% and decreased 3.1%, respectively; and commercial electric and natural gas loads decreased 3.6% and 8.9%, respectively. Industrial customers, who represent 4.0% of the Company's total retail revenue and are generally transmission and transportation services which are not volumetric in nature, are not expected to be materially impacted. Revenue reductions are partially offset by the effects of decoupling. Decoupling revenue during the nine months ended September 30, 2021 was $12.4 million that was over collected for electric and $7.4 million of revenue that was recognized for natural gas, as compared to $37.6 million and $6.8 million revenue that was recognized in the same period of 2020 for electric and natural gas, respectively.
Due to business disruptions caused by the COVID-19 pandemic, the Company has incurred increased costs and partially offsetting cost savings through the period ended September 30, 2021. 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, 2021, PSE deferred $23.9 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 $13.7 million as of September 30, 2021.
On June 30, 2021, Washington State lifted most then-existing restrictions. As a result, the Company anticipates that electric and natural gas loads may be less impacted going forward, however, continued work at home initiatives remain in effect for many businesses, which may impact electric and natural gas loads, particularly among residential and commercial customers. Risks to these assumptions include the duration, severity, and potential resurgence of the virus, government proclamations related to managing public health, and fiscal stimulus policies to support economic recovery.
On September 30, 2021, the Company announced that in order to comply with state and federal vaccine mandates all employees and contingent workers are required to be fully vaccinated against COVID-19 by December 8, 2021. The government vaccination mandate may impact the Company's and vendor staffing levels, which could affect storm response and the timeliness of our response to customers' inquiries.
Further detail regarding the factors and trends affecting performance of the Company during the nine months ended September 30, 2021, 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 2021 and will continue to do so in future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process.  The principal business, economic and other factors that affect PSE'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;
36

•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;
•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, or the Company duringimpact of civil unrest to infrastructure or preventing access to infrastructure; and
•Risks due to pandemics, including supply shortages, rising costs, disruption to vendor or customer relationships, the fiscal quarter ended September 30, 2017 is set forth below in this "Overview" section as well as in other sectionspotential for reputational harm, the impact of Management's Discussiongovernment, business and Analysis.company closure of facilities, customer or contract defaults; concerns of safety to employees and customers, potential costs due to quarantining of employees and work-from-home policies.


Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 20172021 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 through a rate case on a regular and frequent basis in the foreseeable future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

General Rate Case FilingWashington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. The Washington Commission and Washington state law also set natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.
On January 13, 2017, PSE filed itsMay 3, 2021, the Washington Governor signed legislation passed by the state legislature that would require investor-owned utilities to file a multiyear rate plan for two, three, or four years as part of a general rate case (GRC) filed with the Washington Commission whichon or after January 1, 2022. For the initial rate year, the legislation requires the Washington Commission to ascertain and determine the fair value for rate-making purposes of the property in service as of the date that rates go into effect. Utilities would be bound to the first and second year of a multiyear rate plan and can file for a new rate plan in years three or four. If a company earns greater than a half percent above its authorized rate of return on a regulated basis, revenues above the level must be deferred for funds to customers or another determination by the Washington Commission in a subsequent adjudicative proceeding. The Washington Commission must also set performance measurements to be assessed in the multiyear rate plan.

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
37

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

General Rate Case
PSE filed a GRC with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.74%,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%4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s purchased gas adjustment (PGA) deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.05%, annually. The filing was subsequently suspended, which means thatand the final rates granted in the proceeding will go into effect no later than December 13, 2017.natural gas increase to $1.3 million, or 0.15%, and became effective October 15, 2020 and October 1, 2020, respectively.
On August 6, 2020, PSE filed a supplemental filingpetition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the GRC on April 3, 2017, which among other things provided updatesInternal Revenue Service (IRS) normalization and consistency rules. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. 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 is approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE has requested it be allowed to track and, if appropriate recover, pending the outcome of the contested issues betweenIRS ruling.
On July 30, 2021, the settling parties.IRS issued a PLR to PSE which concludes that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is an impermissible methodology under the IRS normalization and consistency rules. The settlement agreement providesPLR requires that PSE request the Washington Commission allow adjustments to its rates to bring PSE back into compliance with IRS rules. Accordingly, on August 10, 2021, the Commission notified parties of their intent to modify the final orders to address the IRS ruling in their PLR and provided parties the opportunity to comment before a final determination is made. 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. This led to a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%. In the order the Washington Commission also approved the collection of the revenue differences tracked since the 2019 GRC rates went into effect within Schedule 141X. The annualized overall rate impact for this element is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a weighted costtotal of capital$18.9 million with rates effective October 1, 2021. To reflect the impact of 7.60% or 6.55% after-tax,the PLR, PSE has recorded a regulatory asset and a capital structureadditional revenues of 48.5%$24.7 million 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 Augustits operating results through September 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.2021.


38

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 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 set at the number of customers which exist in a given testFollowing each calendar 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 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 onApril time period.
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.
On April 28, 2017,23, 2020, the Washington Commission approved PSE's requestPSE’s filing to changecorrect 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.As part of this filing, PSE will true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling 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 a reduction in electric decoupling deferral and revenueapproved the multi-party settlement agreement which was filed within PSE’s PCORC filing. 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, 2021, 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 Accounting Standards Codification (ASC) 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated all currentthat $2.0 million of electric deferred revenues forrevenue would not be collected within 24 months of the annual period; therefore, a reserve adjustment was booked to 2021 electric and naturaldecoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue.
The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Electric:
May 1, 20211
1.0%$21.4
January 1. 2021(1.0)(20.6)
October 15, 20202
(0.5)(10.2)
May 1, 20200.22.0
May 1, 20190.920.6
Natural Gas:
May 1, 20211.5%$15.0
May 1, 2020(0.5)(4.8)
May 1, 2019(5.3)(45.9)
_______________
1.For the electric rates effective May 1, 2021, there was $24.1 million of excess deferred revenues for delivery and fixed power costs which could not be set in rates until May 1, 2022 due to 3% rate cap; there was no excess earnings that impacted both electric and natural gas revenue change. For electric and natural gas rates effective May 1, 2020 and May 1, 2019, there were no adjustmentsexcess earnings that impacted the approved revenue change.
2.The 2019 GRC final order lengthened the recovery period from original one-year recovery to 2017 decoupling revenues other thantwo-year recovery to record the previously unrecognized decoupling deferrals of $20.8 million.April 2022.

Other Proceedings
39

Microsoft
On October 7, 2016, PSE filed a tariff to provide open access service to a narrow set 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 access 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 their 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 in the region by a developer under contract to PSE which will meet the demand for this voluntary renewable energy product project.


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, 2017,2021, in its PCA mechanism, PSE under recovered its powerallowable costs by $8.9$49.7 million of which no amount$20.3 million was apportioned to customers.customers and $1.2 million of interest was accrued on the deferred customer balance. This compares to an overunder recovery of powerallowable costs of $1.4$51.5 million for the nine months ended September 30, 20162020, of which no amounts were$21.9 million was apportioned to customers. Although load increasedcustomers and accrued $1.6 million of interest on the total deferred customer balance.

Power Cost Adjustment Clause Filing
PSE exceeded the $20.0 million cumulative deferral balance in 2017 comparedits PCA mechanism in 2020. PSE filed to 2016 that increaserecover the deferred balance in Docket UE-210300, effective December 1, 2021, and the Washington Commission approved PSE’s request on September 30, 2021. During 2020, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest.
The following table sets forth power cost adjustment clause filing approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase
(Decrease)
in Revenue
(Dollars in Millions)
December 1, 20202.1%$43.9
October 15, 2020(0.2)(3.3)
July 3, 20201.223.9
July 1, 20191
(1.2)(24.9)
May 1, 20190.13.3
_______________
1.The rates for Microsoft Special Contract portion was offset by a decreasezeroed out effective July 3, 2020. The actual residual amounts resulting at July 31, 2020 were included in 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.electric Schedule 129 Low Income Program rates that became effective October 1, 2020.


40

Electric Conservation Rider
On April 28, 2017,The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission approved PSE's request to change rates under its electric conservation rider mechanism,and the corresponding expected annual impact on PSE’s revenue based on the 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 increase for electric customers of $16.5 million, or 0.7%, annually.dates:

Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 2021(0.6)%$(12.3)
May 1, 20200.917.8
May 1, 2019(0.9)(17.5)

Electric 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 $0.9 million, or 0.04%, annually.adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2021(0.1)%$(1.7)
May 1, 20200.071.4
May 1, 2019(0.2)(5.1)


Federal Incentive Tracker Tariff
On October 31, 2017, PSE filed with the Washington Commission an annual true-up and rate filing to PSE'sThe Federal Incentive Tracker Tariff passes through to customers the benefits associated with an effective date of January 1, 2018.the wind-related treasury grants. The proposed true-up filing as originally filed, resultedresults 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 thefor pass-back of treasury grant amortization and $10.4 million representspass-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 pass through of interest. This filing represents an overall average rate increase of 0.2%, annually.forecasted load set in rates. Rates change annually on January 1.
On December 22, 2016,The following table sets forth the federal incentive tracker tariff revenue requirement approved by the Washington Commission approvedand the corresponding expected annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with animpact on PSE’s revenue based on the 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 increase of 0.3%, annually.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, 20210.3%$(29.5)
January 1, 2020(0.04)(37.8)
January 1, 20190.1(38.7)

41

Residential Exchange Benefit
On September 28, 2017,The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA).  Rates change biennially on October 1.
The following table sets forth residential exchange benefit adjustments approved by the Washington Commission approvedand the rate filing to PSE's Residential Exchange Benefit Tariff, with ancorresponding expected annual impact on PSE’s revenue based on the effective date of October 1, 2017. The filing resulted in a total credit of $80.8 million to be passed back to eligible customers over the twelve months beginning October 1, 2017.  This filing represents an overall average rate decrease of 0.6%, annually.dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Total credit to be passed back to eligible customers
(Dollars in Millions)
November 1, 20210.4%$(75.7)
October 12, 20190.01(81.8)
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 itsThe natural gas 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 conversation 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 decrease for natural gas customers of $1.0 million, or 0.1%, annually.effective dates:

Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2021(0.2)%$(1.5)
May 1, 20200.43.5
May 1, 20190.11.1

Natural Gas Property Tax Tracker Mechanism
On April 28, 2017,The purpose of the Washington Commission approved PSE's annual filing request to change rates under its natural gas property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective May 1, 2017, which would result in a rate decrease for natural gas customers of $1.1 million, or 0.1%, annually.dates:
Effective DateAverage Percentage Increase (Decrease) in RatesIncrease (Decrease) in Revenue (Dollars in Millions)
May 1, 20210.3%$3.2
May 1, 2020(0.3)(2.8)
May 1, 2019(0.2)(1.6)

42


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 filingthe cost recovery mechanism (CRM) is to recover capital costs related to projects included in PSE's pipeline replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.
The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20210.5%$4.9
November 1, 20201.210.6
November 1, 20190.87.0
November 1, 20180.55.0

Purchased Gas Adjustment
PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the CRMWashington 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 September 17, 2021, PSE filed with the Washington Commission proposed November 2021 PGA rates, iswhich are expected to go into effect on 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. Those rate increases will be set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B.
On October 27,
The following table presents the PGA mechanism balances and activity at September 30, 2021 and December 31, 2020:
 
Puget Sound Energy
(Dollars in Thousands)At September 30,At December 31,
PGA receivable balance and activity20212020
PGA receivable beginning balance$87,655 $132,766 
Actual natural gas costs218,934 314,792 
Allowed PGA recovery(251,633)(363,886)
Interest1,312 3,983 
PGA receivable ending balance$56,268 $87,655 

43


The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20215.8%$59.1
November 1, 20207.770.0
October 1, 2020(3.9)(35.5)
November 1, 20191
13.4118.3
May 1, 20192
6.354.0
_______________
1.The 2019 GRC final order lengthened the recovery period from two to three years.
2.The rate for out of the cycle May 2019 PGA (Supplemental A) filing was set to zero effective May 1, 2020, The actual residual amount resulting was included in annual PGA filling effective November 1, 2020.


Other Proceedings
Voluntary Long-Term Renewable Energy
Effective September 2016, the Washington Commission approved PSE's CRM natural gas tariff filingrevision to create an additional voluntary renewable energy product. This provides customers with electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000 MWh) and government customers. The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW which went into operation on November 7, 2020. The project is fully subscribed and the twenty-one customers under phase 1 of the program began taking service in November 2020.
In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase 2 project is the 150 MW Lund Hill Solar facility to be located in Klickitat County, Washington. The solar facility is expected to achieve commercial operation in 2021 and serve twenty customers. 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 Lund Hill Solar PPA.

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.Tariff WN U-60. The purpose of this filing is to recover capital costs relatedincorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to enhancingmitigate the safetyeconomic impact of the natural gasCOVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution system.by $4.5 million under the CACAP program. The impactCACAP-1 program successfully distributed over $8.9 million in bill assistance funds to over 15,000 households from its inception in April 2020 through the CRM rates is an annual revenue increase of $5.6 million, or 0.6%, annually.

Purchased Gas Adjustmentprogram end date on September 30, 2020.
On October 26, 2017,March 28, 2021, the Washington Commission approved PSE's PGAPSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance per year for each qualifying low-income household. The CACAP-2 total program budget is $20.0 million for electric customers and $7.7 million for natural gas tariff filing with an effective datecustomers. Natural gas funds may be used for electric bills if necessary. Customers may apply for CACAP-2 more than once during the 12-month program year of November 1, 2017, which reflects changes 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 $30.8 million, or 3.3%, annually with no impact on net operating income.October-September.
On October 27, 2016,15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Supplemental CACAP would
44

utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Low Income Program (PSE HELP). The Supplemental CACAP benefits, for both electric and natural gas residential customers, would be a combined total of $34.5 million and be capped at $23.7 million and $10.8 million, respectively. Additionally, the Supplemental CACAP filing proposed to revise the CACAP-2 total program budget to $27.7 million for electric customers (instead of $20.0 million for electric customers and $7.7 million for natural gas customers). The Supplemental CACAP budget for natural gas customers of $10.8 million would be used for both the CACAP-2 program and the Supplemental CACAP program benefits.
The Supplemental CACAP benefits would be available to PSE’s residential customers who have a past due balance on their PSE electric or natural gas service account and who have a total net household income which is at or below 200% of the federal poverty level guidelines, based on household, as determined by the Company. The Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. If the Supplemental CACAP proposed filing is approved by the Washington Commission, approved PSE's PGA natural gas tariff filingPSE would apply the Supplemental CACAP benefits to qualifying residential service accounts automatically with an effective date of November 1, 2016, which reflects changes in wholesale natural gasopt-out option. Both CACAP-2 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.Supplemental CACAP would be administered until funds are exhausted.

For additional information, see Note 6,7, "Regulation and Rates" to the consolidated 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. Additionally, a ratings downgrade could impact the Company's ability to issue dividends, see Dividend Payment Restriction in Item 2 of this report for further details. 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 air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
Compliance with these or other future laws and regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.


Other Challenges and Strategies
Competition
PSE’s electric and natural gas utility retail customers generally do not have the ability to choose their electric or natural gas supplier; 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.


45

Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the three and nine months ended September 30, 2020, and 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.  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.



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, 2020 and 2021:
psd-20210930_g3.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
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
46
___________________
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.


Three Months Ended September 30, 2017 compared2020 Compared to 20162021
Electric Operating Revenue
Electric operating revenues increased $42.2$112.4 million from the prior year primarily due to an increase in electric retail sales of $49.8 million, an increase in sales to other utilities of $50.1 million, and transportation and other revenues of $24.9 million; partially offset by a decrease in decoupling revenue of $13.6$10.0 million higher retail sales of $13.0 million,and a decrease in other decoupling revenue of $7.9 million and other electric operating revenues of $3.6$2.4 million. These items are discussed in detail below.
•Electric retail sales increased $13.0$49.8 million primarily due to a $7.0an increase of $38.3 million in rates compared to the prior year and an increase of $11.5 million from an increase in retail electricity usage of 67,864 Megawatt Hour (MWhs) related2.3%. The increase in rates is primarily due to average retail customer growththe tariffs filed pursuant to the Company's most recent PCORC, GRC and PCA filing effective July 1, 2021, October 15, 2020 and December 1, 2020, respectively. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of 13,828 customers, or 1.2%; andthis report for rate changes. The additional usage was due to an increase in ratescommercial and residential usage of $6.0 million.
3.4% and 2.1%, respectively, primarily driven by an increase in heating degree days of 76.5%, an increase in retail customers of 1.3% compared to 2020 and by COVID-19 business shut downs, primarily impacting commercial customers in 2020.

•Sales to other utilities increased $50.1 million due to a 107.0% increase in market prices and a 67.4% increase in volumes. The increase to the actual price of sales was due to higher market power prices driven by an increase in natural gas prices nationwide following constrained supply related to summer storms in the Southeast United States, along with increased demand from overseas markets. Higher sales volumes were the result of increased volume from PSE's gas-fired generation of 30.3%, driven by greater value in the market.
•Decoupling revenue decreased $10.0 million, primarily attributable to a $5.4 million and $4.6 million decrease in delivery and fixed production cost (FPC) deferral revenues, respectively, in the current period compared to the same period in 2020. This was driven by increased $13.6usage as noted above in the retail revenue section. This resulted in actual revenues being greater than allowed decoupling deferral revenues in the current year, whereas in the prior year actual revenues were lower compared to allowed revenues.
•Other decoupling revenue decreased $2.4 million primarily due to a $3.1 million increase in year-over-year amortization of prior year undercollections due to increased usage. This is partially offset by a $0.8 million increase related to GAAP alternative revenue program recognition guidelines. As of quarter ended September 30, 2020, there were $2.0 million of decoupling revenues that were not anticipated to be collected within 24 months, and therefore were deferred. In the same period for 2021, $1.2 million of decoupling revenues were anticipated to not be collected within 24 months and have been deferred.
•Transportation and other revenue increased $24.9 million primarily due to the following: (i) an increase in net wholesale non-core gas sales of $16.9 million due to a $42.2 million increase in sales driven by a 117% increase in the average price, a 15% increase in sales volume, and a $12.7 million gain on natural gas financial hedges, which were partially offset by a $38.0 million increase in the total cost of wholesale gas sold due to an increase in the average price and increase in sales volume; (ii) revenue recognition of $4.4 million as a result of the IRS PLR which concluded the EDIT methodology that was included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for more information and (iii) an increase of $2.1 million in transmission revenue primarily related to short-term point to point transmission sales; partially offset by (iv) no production tax credit (PTC) deferral revenue for the re-purpose of the PTCs in 2021 compared to $3.1 million in 2020.

Electric Power Costs
Electric power costs increased $113.5 million primarily due to an increase of $15.7$75.3 million in decoupling revenue associated with the fixed cost deferral of the PCA mechanism in 2017. This waspurchased electricity costs and an increase of $38.6 million of electric generation fuel expenses; partially offset by $2.1$0.4 million of residential exchange credits. These items are discussed in lower decoupling deferralsdetail below.
•Purchased electricity expense increased $75.3 million due to a 64.6% increase in 2017wholesale prices driven by higher pricing trends in 2021 compared to 20162020 when prices were down due to higher electricity usage, as noted above.
Other decoupling revenue increased $7.9 millionproduction, mild weather and a surplus due to reduced sharing of rate of return (ROR) excess earnings of $10.2 million from over earningsdecreased demands caused by COVID-19. Increased wholesale prices in 2016 as compared2021 are due to no earnings sharing in 2017. This was partially offsethigher market power prices driven by an increase of decoupling cash collections of $1.1 million as comparedin natural gas prices nationwide following constrained supply related to 2016 due to an additional $9.0 million being set into rates.
summer storms in the Southeast United States, along with increased demand from overseas markets.
Other electric operating revenue•Electric generation fuel expense increased $3.6$38.6 million primarily due to a $35.1 million increase in CT generation of acosts as CT production tax credit (PTC) deferral of $5.0 million in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expiredincreased 30.3% driven by greater value in the first quartermarket and an increase in customer usage as mentioned previously in sales to other utilities and electric retail sales, respectively.

47


The following chart displays the details of 2017. This wasPSE's electric margin changes for the nine months ended September 30, 2020 and 2021:
psd-20210930_g4.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Nine Months Ended September 30, 2020 Compared to 2021
Electric Operating Revenue
Electric operating revenues increased $297.4 million from the prior year primarily due to an increase in electric retail sales of $188.3 million, increase in transportation and other revenues of $81.6 million, an increase in sales to other utilities of $70.4 million and an increase in other decoupling revenue of $7.2 million; partially offset by a decrease in net wholesale natural gas sales of $1.8 million.

Electric Energy Costs
Purchased electricity expense increased $21.0 million primarily due to a $13.9 million 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 and 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$50.1 million. These items are discussed in detail below.
•Electric retail sales increased $86.7$188.3 million primarily due to a $77.5an increase of $103.7 million in rates compared to the prior year and an increase of $84.6 million from an increase in retail electricity usage of 743,073 MWhs related to a 28.0%5.3%. The increase in heating degree days;rates is primarily due to the tariffs filed pursuant to the Company's most recent PCORC, GRC and Power Cost Adjustment filing effective July 1, 2021, October 15, 2020 and December 1, 2020, respectively. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes. Residential and commercial usage increased 5.2% and 6.2%, respectively driven by an increase in ratescooling and heating degree days of $9.2 million.
13.6% and 4.6%, respectively, an increase in retail customers of 1.3% compared to 2020, and by COVID-19 business shut downs, primarily impacting commercial customers in 2020.
Decoupling revenue decreased $9.3•Sales to other utilities increased $70.4 million due to $19.8 milliona 116.2% increase in lower decoupling deferralsthe actual price of sales and a 15.0% increase in 2017 comparedvolumes. The increase to 2016the actual price of sales was due to higher electricity usage, as noted above.market power prices, which were 101.8% higher than in 2020, driven by increases in natural gas prices. Higher sales volumes were the result of increased volume from PSE's gas-fired generation of 16.3%, particularly in May through September driven by greater value in the market.
48

•Decoupling revenue decreased $50.1 million, primarily attributable to a $25.4 million and $24.7 million decrease in delivery and FPC deferral revenues, respectively. This was partially offsetdriven by an increase of $10.5 millionhigher usage in the current period compared to the same period in 2020. This resulted in actual revenues being greater than allowed decoupling revenue associated withdeferral revenues in the fixed cost deferral ofcurrent year, whereas in the PCA mechanism in 2017.
prior year actual revenues were lower compared to allowed revenues.
•Other decoupling revenue increased $2.8$7.2 million, primarily due to decreasesa $10.1 million increase related to GAAP alternative revenue program recognition guidelines. As of the year to date ended September 30, 2020, $4.1 million of decoupling revenues were not anticipated to be collected within 24 months, and therefore were deferred. As of December 31, 2020, there was $8.0 million of decoupling revenue that was not anticipated to be collected within 24 months, and therefore was deferred. The full $8.0 million deferred was recognized in ROR excess earnings sharingthe first quarter of $8.62021, but is partially offset by $2.0 million of 2021 revenue currently deferred and a $2.9 million increase in collection of prior year undercollected revenues due to an increase in amortization rates.
•Transportation and other revenue increased $81.6 million primarily due the following: (i) an increase in net wholesale non-core gas sales of $29.6 million due to no expectation to over earna $56.2 million increase in 2017sales driven by a 102% increase in the average price, a 7% decrease in sales volume, and 24-month revenue reserve of $1.6a $18.6 million from no reserve in 2017. This wasgain on natural gas financial hedges, which were partially offset by a $7.4$45.5 million increase in the total cost of decoupling cash collections as compared to 2016wholesale gas sold due to an additional $9.0increase in the average price and increase in sales volume; (ii) an increase in PTC deferral revenue of $28.0 million being set into rates.
for the re-purpose of the PTCs driven by an increase in current period taxable income; (iii) revenue recognition of $20.4 million as a result of the IRS PLR which concluded the EDIT methodology that was included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for more information; (iv) an increase in AMI return deferral revenue of $3.7 million; (v) an increase of $2.6 million in rent from wireless pole contacts and (vi) an increase of $2.1 million in transmission revenue primarily related to short-term point to point transmission sales. These increases were partially offset by a decrease in revenue subject to refunds of $7.4 million primarily due to the passback of the regulatory deferral to customers for the tax rate decrease in the Tax Cuts and Jobs Act in 2020 of $8.3 million.

Other electric operating revenueElectric Power Costs
Electric power costs increased $32.1$207.9 million primarily due to an increase of $152.0 million of purchased electricity costs; and $58.9 million of electric generation fuel expenses; partially offset by $3.0 million of residential exchange credits. 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$152.0 million primarily due to a $45.5 million increase related to long-term purchases, a $13.3 million34.7% increase in EIM purchases,wholesale prices due to prices trending higher in 2021 compared to 2020 when prices were down due to higher production, mild weather and a $8.3 millionsurplus due to decreased demands caused by COVID-19 and a 2.0% increase in the power exchange contract with Pacific Gas & Electric Company. These increases were due to additionalwholesale electricity purchases. The increase in purchases was primarily driven by an increase in load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind productionas well as an increase in other contracted resources 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 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 and generation resources.
23.7%.



•Electric generation fuel expense decreased $13.6increased $58.9 million primarily due to a $10.7$55.9 million increase in combustion turbine (CT) generation costs driven by a 16.1% increase in CT production, higher fuel costs, and a decrease in the total costMid-Columbia hydro and non-firm energy purchases of natural gas burned driven by lower volumes burned offset by an increase in the average price of the natural gas burned11.3% and a $2.90.9%, respectively.
•Residential exchange expense credits increased $3.0 million decrease in the cost of coal burned due to a lower average prices of coal burned in 2017 compared to 2016. 
Residentialthe same period in 2020 as a result of higher electric residential sales volumes associated with the BPA residential exchange credits increased $3.7 million resulting from increased electricity usage as rates remain consistent in both periods.program. The REPresidential exchange credit is a pass-through tariff item with a corresponding credit 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.


49



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, 2020 and 2021:
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
psd-20210930_g5.jpg
_______________
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.

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




Three Months Ended September 30, 2017 compared2020 Compared to 20162021
Natural Gas Operating Revenue
Natural gas operating revenuedecreased $2.9 increased $10.5 million primarily due to an increase of $11.9 million in total retail sales, and a $2.0 million increase in transportation and other revenue; partially offset by a decrease of $3.4$2.2 million in other decoupling revenue and a decrease of $0.9$1.2 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 $11.9 million primarily due to an increase in rates of $7.3 million and a decrease$4.6 million increase due to an increase in natural gas load of $5.3 million from a reduction4.2%. The increase in rates is due to the PGA increase effective November 1, 2020 and the tariffs effective October 1, 2020 filed pursuant to the Company's most recent GRC. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of 2,727 therms sold from lower heating degree daysthis report for natural gas rate changes. The increase in 2017;natural gas load was primarily driven by increased commercial customer usage in 2021 primarily due to COVID-19 business shut downs in 2020 and partially offset by an increase of $4.4decreased industrial usage primarily from interruptible customers.
50

•Decoupling revenue decreased $2.2 million, primarily attributable to increased usage in the current period compared to the same period in 2020, as noted above in the retail revenue section This resulted in actual natural gas revenues being higher than allowed natural gas revenues in the current period, whereas in the same period in 2020, allowed revenues were higher than actual revenues.
•Other decoupling revenue decreased $1.2 million, due to rate adjustments.
an increase in current period amortization of prior year revenues compared to the same period in 2020. This is attributable to an average increase in amortization rates from increased cumulative deferral revenues to recover from customers.
Other decoupling•Transportation and other revenue decreased $3.4 increased $2.0 million primarily due to an increase in Rule 7 qualifying payment revenue of $2.4 million due to more subsequent customers contributing to the new customer rate in 2021 as compared to 2020.

Natural Gas Energy Costs
•Purchased natural gas expense increased $4.3 million due to an increase in the PGA rates in November 2020 and an increase in natural gas usage of 4.2% as stated in the natural gas retail sales section above.


The following chart displays the details of PSE's natural gas margin changes for the nine months ended September 30, 2020 and 2021:
psd-20210930_g6.jpg
_______________
*Includes decoupling cash collections, ROR excess earnings, sharing of $6.2 million of which $4.3 million was accrued for over earnings in 2017. This was partially offset by a decrease of $2.7 million inand decoupling 24-month revenue reserve as compared to 2016 as no reserve was recorded in 2017.reserve.

51




Nine Months Ended September 30, 2017 compared2020 Compared to 20162021
Natural Gas Operating Revenue
Natural gas operating revenueincreased $90.4$49.8 million primarily due to an increase of $125.5$46.7 million in total retail sales, due to additional natural gas usagea $2.9 million increase in transportation and other revenue and an increase of $0.6 million in other decoupling revenue of $1.6 million;revenue; partially offset by a $38.3decrease of $0.3 million reduction in other decoupling revenue. These items are discussed in detail below.
•Natural gas retail sales revenue increased $125.5$46.7 million due to an increase in rates of $33.7 million and an increase in natural gas load of 2.1%, or $13.1 million of natural gas sales. The increase in rates is primarily due to the PGA increase effective November 1, 2020 and the tariffs effective October 1, 2020 filed pursuant to the Company's most recent GRC. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. Natural gas load increased primarily due to an increase of $121.7 million fromin commercial customer usage in 2021 primarily due to COVID-19 business shut downs in 2020 and an additional 121,510 therms sold related to a 28.0% increase in heating degree days;days of 4.6%.
•Transportation and an increase of $3.8 million due to rate adjustments.
Decouplingother 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$2.9 million primarily due to the following: (i) revenue recognition of $4.4 million as a $22.9result of the IRS PLR which concluded the EDIT methodology that was included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for more information; (ii) an increase in Rule 7 qualifying payment revenue of $2.6 million reversal of previously deferred revenues relateddue to more subsequent customers contributing to the 24-monthnew customer rate in 2021 as compared to 2020; (iii) an increase in AMI return deferral revenue reserve.  The increase wasof $1.7 million and (iv) no entitlement constraint charges in 2021 as compared to $1.5 million in 2020. These increases were partially offset by an increasea decrease in decoupling cash collectionsprovision for rate refunds of $13.0$4.6 million duein 2021 as compared 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.
2020.


Natural Gas Energy Costs
•Purchased natural gas expense increased $42.8$6.0 million directly relateddue to a 22.7%an increase in the PGA rates in November 2020 and an increase in natural gas usage.usage of 2.1% as stated in the natural gas retail sales section above.

52

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, 20172020 and 2016:2021:

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)
psd-20210930_g7.jpg


Three Months Ended September 30, 2017 compared2020 Compared to 20162021
Other Operating Expenses
•Net unrealized (gain) loss on derivative instrumentsincreased $6.4$48.6 million from a loss of $6.3 million due to a $6.6net gain of $88.5 million increase infor the quarter ended September 30, 2021. One of the drivers for the change related to the net settlements of contracts withelectric trades previously unrealized losses.
recorded as $7.5 million in loss, offset by the settlement of natural gas trades previously recorded at a $29.1 million in gain. The other driver related to the change in the weighted average forward prices for electric and natural gas. Specifically, electric price increased 30.4% resulting in $28.5 million gain for electric. Natural gas price increased 4.4% resulting in $41.7 million gain for natural gas. For further details, see Note 4, "Accounting for Derivative Instruments and Hedging" to the consolidated financial statements included in Item 1 of this report.
Depreciation•Utility operations and amortizationmaintenance expense increased $10.8$2.8 million primarily due to an increase of $3.7$3.1 million of amortizationadministrative and general expenses due to higher labor and overhead expenses driven by additional vice president positions as well as less labor charged to capital projects.
•Non-utility expense and other expense increased $18.4 million primarily due to $12.9 million related to the PWI land sale, which comprised of $11.0 million for the cost of the sale and $1.9 million of selling expenses. Additionally, PSE had an increase for the long term incentive plan of $3.6 million due to estimated performance results and an increase of $1.9 million related to biogas purchase expense primarily due to an increase in the third quarter King County, Washington royalty estimate, which was $1.4 million due to higher net revenues in 2021 as compared to $0.6 million in the prior year.
•Taxes other than income taxes increased $6.3 million primarily due to an increase of computer software assets, $2.2 million of depreciation expense related to net additions of $183.0 million of electric distribution and general assets and an increase of $1.7$2.5 million related to an additional $174.8the state excise tax and $2.9 million of natural gas distribution assets.related to municipal taxes driven by the increase in retail revenue in 2021 as compared to 2020.

53


Other Income, Interest Expense and Income Tax Expense

•Interest expense decreased $4.4 million primarily due to decreased deferred compensation interest expense of $1.9 million driven by higher deferred compensation distributions in 2021 compared to 2020 and $1.2 million in PTC interest expense due to PTC monetization in 2020.
•Income tax expense increased $6.0$17.3 million primarily driven by higheran increase in pre-tax book income.
income of $17.5 million, decrease in net ARAM reversal of $2.5 million, and partially offset by the amortization of unprotected EDIT of $2.0 million, see Management's Discussion and Analysis, "Regulation and Rates", included in Item 2 of this report for more information on ARAM.



The following chart displays the details of PSE's operating expenses and other income (deductions) for the nine months ended September 30, 2020 and 2021:

psd-20210930_g8.jpg


Nine Months Ended September 30, 2017 compared2020 Compared to 20162021
Other Operating Expenses
•Net unrealized (gain) loss on derivative instruments decreased $80.3increased $169.2 million to a net gain of $172.8 million for the nine months ended September 30, 2021. One of the drivers for the change related to the net settlements of electric trades previously recorded as $0.2 million in loss, offset by the settlement of $23.1natural gas trades previously recorded as $44.7 million of which $57.2 million was duein gain. The other driver related to decreasesthe change in the weighted average forward market prices of wholesale electricityfor electric and natural gas. Specifically, electric price increased 99.8% resulting in $98.5 million gain for electric. Natural gas price increased 42.6% resulting in $115.2 million gain for natural gas. For further details, see Note 4, "Accounting for Derivative Instruments and $23.1 million dueHedging" to a decreasethe consolidated financial statements included in settlementsItem 1 of contracts with previously unrealized losses.this report.
54

•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$10.5 million primarily due to $7.1increases of (i) $6.0 million of rentdistribution maintenance related to higher maintenance costs associated with construction, vegetation management, inspections and emergent outage work; (ii) $5.4 million of uncollectible accounts and customer service expenses, driven by higher bad debt expense, primarily at the corporate office locations, $5.3low income assistance, and clean energy spending; and (iii) $3.1 million of injuries and damages expense primarily fordue to higher liability claims and insurance premium, $4.6costs. The increases were partially offset by decreased (i) customer records and collection expense of $3.9 million due to reduced call center and billing costs related to paperless billing adoption and (ii) $3.5 million of pensionsdistribution operations miscellaneous expenses driven by service providers unable to perform normal duties during 2020.
•Non-utility expense and benefits other expense $3.9increased $9.0 million primarily due to $12.9 million related to the PWI land sale, which was comprised of $11.0 million for the cost of the sale and $1.9 million of general plant maintenanceselling expenses. Additionally, PSE had an increase for the long-term incentive plan of $2.3 million due to estimated performance results and an increase of $5.1 million related to biogas purchase expense, and $3.1 million of outside services employed expenses. This wasas compared to the prior year. These increases were partially offset by a $7.0 million biogas settlement in 2020 and a decrease in electric transmission and distribution expensenon-qualified pension plan costs of $8.4$4.7 million.
•Depreciation and amortization expense increased $26.7$80.2 million primarily driven by: (i) electric amortization increased by $47.9 million or 168.8% from 2020. This increase is primarily driven by the $28.0 million change in PTC amortization and the completion of the amortization period for the regulatory liability with Microsoft power costs in 2020; (ii) common amortization increased by $15.2 million or 27.9% from 2020 primarily driven by a lower level of depreciation deferred for the GTZ program due to the 2019 GRC order, partially offset by net retirements of $34.3 million, or $8.4 million; (iii) conservation amortization increased by $6.2 million due to an increase in retail usage of 5.3% and 2.1% for electric and natural gas, respectively; (iv) electric distribution depreciation increased a net of $5.1 million or 4.6% from 2020 primarily due to $192.1 million in net additions of electric distribution assets; and (v) natural gas distribution depreciation increased by $4.3 million or 4.8% from 2020 primarily due to $227.2 million in net additions in natural gas distribution assets.
•Taxes other than income taxes increased $19.2 million primarily due to an increase of $11.6$9.8 million of amortization expense related to an increase of computer software assets, $8.7the state excise tax and $7.4 million of depreciation expense duerelated to net additions of $253.7 million of electric transmission, distribution 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.
Taxes other than income taxes increased $26.7 million primarily due to increases in municipal taxes of $9.2 million and state excise taxes of $8.5 million both relateddriven by the increase in retail revenue in 2021 as compared to increased revenue and an increase of $8.8 million in property taxes related to increased property values and expected tax rates.
2020.

Other Income, Interest Expense and Income Tax Expense
•Other income and expense decreased $5.5 million primarily due to $6.3 million of SmartBurn, a pollution control technology that reduces nitrogen oxide, plant investment at Colstrip 3 & 4 which recovery was disallowed in 2020 per order of the Washington Commission in the Company's most recent GRC and an increase in Washington Commission AFUDC of $2.5 million due to an increase in eligible construction work in progress and Washington Commission rates; partially offset by a decrease in PGA interest income of $1.9 million in 2021 as compared to 2020.
•Interest expense decreased $2.1 million primarily due to decreases of $1.3 million in deferred interest expense driven by higher deferred compensation distributions in 2021 compared to 2020 and $1.5 million related to the Lower Snake River treasury grant, a renewable energy incentive program.
•Income tax expensedecreased $8.5 increased $33.0 million primarily driven by loweran increase in pre-tax book income.income of $39.2 million, decrease in net ARAM reversal of $3.1 million, and offset by the amortization of Unprotected EDIT of $9.2 million, see Management's Discussion and Analysis, "Regulation and Rates", included in Item 2 of this report for more information on ARAM.

55


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, 20172020 and 2016 are2021 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-20210930_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, 20172020 compared to 20162021
Summary Results of Operation
Puget Energy’s net income increased for the three months ended September 30, 20172021 by $10.5$39.6 million when compared to the same period in the prior year. The increase is primarily due to PSE's increase inincreased PSE net income. No additional factors significantly impacted














56

Puget Energy
Primarily, all operations of Puget Energy are conducted through PSE. Puget Energy's net income.

Nine Months Ended September 30, 2017 compared to 2016
Puget Energy’s net income decreased(loss) for the nine months ended September 30, 20172020 and 2021 is as follows:

psd-20210930_g10.jpg

Nine Months Ended September 30, 2020 compared to 2021
Summary Results of Operation
Puget Energy’s net income increased for the nine months ended September 30, 2021 by $32.4$212.1 million when compared to the same period in the prior year. The increase is primarily due to PSE'sincreased PSE net income and decreases both interest expense and income tax expense. The decrease in net income. No additional factors significantly impactedinterest expense is a result of lower interest rates on outstanding debt as compared to prior period. Additionally, in 2020, Puget Energy's net income.Energy extinguished certain senior notes which resulted in a loss of $13.5 million. Income tax expense decreased primarily due to a lower effective tax rate driven by increased EDIT amortization.












57

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, 2016,2020, during the nine months ended September 30, 20172021, the Company has entered into two new power supplyElectric Portfolio and serviceElectric Wholesale Market Transaction contracts with estimated payment obligations totaling $729.5$826.5 million through 2028.2042.
For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the year ended December 31, 2020.
The following are the Company's aggregate availability under commercial commitments as of September 30, 2017:2021:
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 facility767,000 — 767,000 — — 
Less: Inter-company short-term debt elimination(30,000)— — — (30,000)
Total Puget Energy commercial commitments$1,567,000 $— $1,567,000 $— $— 
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.
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, 2017,2021, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition, 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 $93.4 million compared to forecasted amounts for the nine months ended September 30, 2021. 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 FERC dam safety standards and to extend the life of the project to meet the 50 year FERC license; (ii) less capital work than anticipated at Colstrip, and (iii) delays in the rollout of AMI. Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $677.0$662.2 million for the nine months ended September 30, 2017.2021. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
Capital Expenditure Projections
(Dollars in Millions)202120222023
Total energy delivery, technology and facilities expenditures$951.3$973.9$1,294.1
Capital Expenditure Projections     
(Dollars in Thousands)2017 2018 2019
Total energy delivery, technology and facilities expenditures$1,092,000
 $972,000
 $809,000


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.  

58


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)20212020Change
Net income$222,846
 $256,382
 $(33,536)Net income$351,959 $159,420 $192,539 
Non-cash items1
562,232
 455,355
 106,877
Non-cash items1
391,584 497,676 (106,092)
Changes in cash flow resulting from working capital2
164,451
 66,718
 97,733
Changes in cash flow resulting from working capital2
68,070 119,266 (51,196)
Regulatory assets and liabilities(83,370) (138,096) 54,726
Regulatory assets and liabilities(87,076)(90,513)3,437 
Other noncurrent assets and liabilities3
(33,734) 10,128
 (43,862)
Purchased gas adjustmentPurchased gas adjustment31,387 30,859 528 
Other non-current assets and liabilities3
Other non-current assets and liabilities3
(9,484)(26,391)16,907 
Net cash provided by operating activities$832,425
 $650,487
 $181,938
Net cash provided by operating activities$746,440 $690,317 $56,123 
_______________
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, 20172021 compared to 20162020
Cash generated from operations for the nine months ended September 30, 20172021 increased by $181.9$56.1 million including a net income decreaseincrease of $33.5$192.5 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 decreased $106.1 million primarily due to changes ina $169.2 million change from a net unrealized gain on derivative instruments of $80.3$3.6 million to a net unrealized gain on derivative instruments of $172.8 million; a $28.0 million change in PTC utilization; equity AFUDC of $1.5 million; recognition of a $24.7 million regulatory asset as a result of the IRS PLR which concluded the EDIT methodology that was included in rates following the 2019 GRC order was impermissible, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for more information; and $6.3 million related to loss in 2020 due to writing off the Smart Burn project at Colstrip, offset by increases in depreciation and amortization of $26.7$74.1 million, amortization of Tax Cuts and Jobs Act over collection of $12.0 million, conservation amortization of $6.2 million, and deferred income taxes of $31.5 million. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.
•Cash flowflows resulting from changes in working capital increased $97.7 million due decreased $51.2 million. As a result of rate increase and higher usage as noted in Results of Operations within Item 2 of this report along with our initiative to changessuspend disconnections of customers for non-payment, cash outflow in accounts receivable unbilled revenue, materialsincreased $83.2 million. The increase of cash outflow in accounts receivable was partially offset by $30.2 million increase of cash inflow in accounts payable and supplies, prepayments, purchased gas adjustments and$1.8 million increase in accrued expenses.
•Cash flowflows resulting from regulatory assets and liabilities increased $54.7$3.4 million primarily due to changesa $31.9 million increase in decoupling and derivativesthe power cost adjustment mechanism, partially offset by changes in purchased gas adjustments.a deferral of $19.0 million of 2021 storm excess costs and a deferral of $9.0 million of bad debt and costs due to COVID-19.
•Cash flow resulting from changes in other non-current assets and liabilities increased $16.9 million primarily due to decreased payments of long-term incentive plan (LTIP) of $14.6 million and $11.0 million due to the PWI land sale in Tumwater, Washington, partially offset by payroll taxes deferral of $9.6 million in 2020.
59


Puget EnergyNine Months Ended
September 30,
(Dollars in Thousands)20212020Change
Net income$(58,155)$(77,721)$19,566 
Non-cash items1
7,747 12,420 (4,673)
Changes in cash flow resulting from working capital2
(16,937)(473)(16,464)
Other non-current assets and liabilities3
(7,964)(8,703)739 
Net cash provided by operating activities$(75,309)$(74,477)$(832)
_______________
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, 20172021 compared to 20162020
Cash generated from operations for the nine months ended September 30, 2017 increased2021, in addition to the changes discussed at PSE above, decreased by $198.3$0.8 million compared to the same period in 2016.2020, which includes a net income increase of $19.6 million.  The net differenceremaining change was primarily impacted by the increase fromfactors explained below:
•Non-cash items decreased $4.7 million primarily due to cash flow providedoutflow of $13.5 million related to the extinguishment of senior notes in 2020, which was partially offset by the operating activitieslower non-cash outflows of PSE, as previously discussed. The remaining variance is explained below:$8.6 million due to changes in deferred taxes.
•Cash flow resulting from working capital decreased $14.6$16.5 million primarily due to a larger$12.9 million decrease caused by the change of eliminations of PSE's intercompany account receivable and account payable balances with Puget LNG and Puget Energy, along with increased cash outflow of $2.9 million in accounts receivable.tax payable and lower other accrued expenses of $0.7 million.


Cash flow resulting from other noncurrent assets and liabilities increased $27.4 million primarily due to changes in other property and investments related to Puget LNG.

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. Our initiative to suspend disconnections of customers for non-payment and the receipt of the Washington Commission approval to waive late fees will impact future cash receipts.
As a result of the 2019 GRC outcome and the continuing negative impacts of tax reform on the Company's cash flows, Puget Energy and PSE's credit rating metrics were negatively impacted. In response to the 2019 GRC order, Moody's released an issuer comment stating the GRC outcome was credit negative but took no formal credit rating action. On July 23, 2020, S&P placed Puget Energy and PSE on CreditWatch with negative implications due the rate case outcome, but later revised to negative outlook. Fitch affirmed Puget Energy and PSE ratings but changed its outlook from stable to negative. On May 27, 2021, S&P revised Puget Energy’s and PSE’s ratings from negative to stable outlook. On June 1, 2021, Fitch also revised its outlook for PE and PSE to stable. Both actions were a result of the passage and signing into law of Washington Senate Bill 5295 which allows for multi-year rate plans and reduction of regulatory lag, as well as other actions taken by management to increase revenue via available rate recovery methods and management of internal expenses. Despite these actions, the rating agencies noted that a lack of sufficient regulatory rate relief over the relative near term could result in negative ratings implications. Although neither Puget Energy nor PSE have any debt whose maturity would be accelerated upon a ratings downgrade, a credit rating downgrade may increase the cost of borrowing for Puget Energy and PSE in future long-term financings or under their existing credit facilities. Any increase in the cost of borrowing may negatively impact Puget Energy
60

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

Puget Sound Energy
Credit FacilitiesFacility
As of September 30, 2017,2021, PSE had two unsecured revolvingan $800.0 million credit facilities which provided, in aggregate, $1.0 billion offacility to meet short-term liquidity needs. These facilities consisted of a $650.0 million revolving liquidity facility (which included a liquidity letter ofThe credit facility and a swingline facility) to be used for general corporate purposes, including as backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which included an energy hedging letter of 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 hadfacility has an accordionexpansion feature which, upon the banks' approval, would increase the total size of these facilitiesthe facility to $1.5$1.4 billion. TheseThe unsecured revolving credit facilities maturefacility matures in April 2019.October 2023.
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 covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2017,2021, 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's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit 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 LIBOR is 1.25% and the commitment fee is 0.175%.
As of September 30, 2017,2021, no amounts wereamount was drawn and outstanding under either facility. No letters ofPSE's credit were outstanding under either facility and $139.0 millionno amount was outstanding under the commercial paper program. Outside of the credit agreements,agreement, PSE had a $3.1$2.5 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.
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, 2017,2021, PSE had no outstanding balance under the Note.


Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests at September 30, 2017,2021, PSE could issue:
•Approximately $2.6$1.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3$2.7 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;2021; and
•Approximately $545.0$798.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $908.3 million$1.3 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, 2017.2021.
61

At September 30, 2017,2021, PSE had approximately $6.9$7.9 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,August 2, 2019, PSE filed a new shelf registration statement under which it may issue as of the date of this report, up to $800.0 million$1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $100.0 million was available to be issued. The shelf registration will expire in November 2019.August 2022.


Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At September 30, 2017,2021, approximately $674.2 million$1.1 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%48.0% at September 30, 20172021, and the EBITDA to interest expense was 5.45.8 to 1.0 for the twelve months ended September 30, 2017.2021.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. At September 30, 2021, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


Long Term Debt
On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2020.

Puget Energy
Credit Facility
At September 30, 2017,2021, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures April 2018.facility. The Puget Energy revolving senior secured credit facility also has an accordion feature, which, upon the banks' approval, would increase the size of the facility to $1.3 billion. The revolving credit facility matures in October 2023.
The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of September 30, 2017,2021, there was $83.1$33.0 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of September 30, 2017,2021, Puget Energy was in compliance with all applicable covenants.


In October 2017,
62

Long-Term Debt
On June 14, 2021, Puget Energy entered into a new $800.0issued $500.0 million credit facility to replace the existing facility. The terms and conditions, including fees,of senior secured notes at an interest rate options, financial covenant,of 2.379%. The notes were issued for a period of 7 years, 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, 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 agreed toEnergy’s $210.0 million term loan up to $200.0 million to Puget LNG to finance Puget LNG’s portion ofon June 23, 2021. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the construction costs of a liquefied natural gas facility located atCompany's most recent Annual Report on Form 10K for the Port of Tacoma. The interest rate for amounts borrowed under the agreement is equal to the one month LIBOR rate in effect on the first day of each month plus the applicable margin Puget Energy would pay on loans under its credit facility. Interest under 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, 2020.


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 3.64.0 to 1.0 for the twelve months ended September 30, 20172021.
At September 30, 2017,2021, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


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


Washington Clean Energy Transformation Act
In May 2019, Washington State passed the 100 Percent Clean Electric Bill that supports Washington's clean energy economy and transitioning to a clean, affordable, and reliable energy future. The Clean Energy Transformation Act (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 each IOU must propose interim targets for meeting the 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend to pursue to meet the standard. The Washington Commission may approve, reject, or recommend alterations to an IOU’s plan. On October 15, 2021 the Company filed a draft Clean Energy Implementation Plan (CEIP) with the Washington Commission in compliance with CETA. The CEIP will be evaluated by the Washington Commission over the course of the following months.
In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive-based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those facilities. IOUs will be allowed to earn a rate of return on certain PPAs and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.
IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.
The law requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time. The Company intends to seek recovery of any costs associated with the clean energy legislation through the regulatory process.

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. On March 6, 2013,PSE has accelerated the Sierra Clubdepreciation of Colstrip Units 3 and 4, per the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss allterms of the Clean Air Act allegations against theGRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover
63

decommissioning and remediation costs for 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, ColstripUnits 1 through 4.
Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 owners, PSE and Talen Energy, agreed to retireat 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 ratesend of the net book value (NBV) at retirement and related decommissioning costs consistentyear due to operational losses associated 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 ofUnits. Colstrip Units 1 and 2 based on the expected shutdown date of July 1, 2022 as ofwere retired effective December 31, 2016. Due2019. The Washington Clean Energy Transformation Act requires the Washington Commission 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 by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as partprovide recovery of the settlement. While PSE has estimatedundepreciated investment and to allow in electric rates all prudently incurred decommissioning, and remediation costs associated with the ARO for Colstrip Units 1 and 2, thefacilities. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.


GreenwoodWashington Climate Commitment Act
On March 9, 2016,In May 2021, Washington enacted the Climate Commitment Act, which establishes a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures.“cap and invest” program for GHG. The Washington Commission Staff completed its investigationDepartment of the incident and filed a complaint on September 20, 2016, seeking upEcology intends 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 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.




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)begin issuing regulations 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 Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. On September 30, 2016, the four companies filed 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 comply2021, with the programs’ first compliance period of the CAR, which began on January 1, 2017.beginning in 2023.


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

Currently under construction, theThe Tacoma LNG facility is expected to be operationalachieved mechanical completion in 2019.February 2021. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. AsPer this allocation of September 30, 2017, Puget LNG has incurred $86.5costs, $238.8 million inof construction work in progress and $0.9 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, 2021. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.



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

Item 3.     Quantitative and Qualitative Disclosure about Market Risk


The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2020.


Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee (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.  


64

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, 2017,2021, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.



Changes in Internal Control over Financial Reporting
There 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, 2021 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, 2017,2021, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.


Changes in Internal Control over Financial Reporting
There 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, 2021 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.
65



PART II            OTHER INFORMATION



Item 1.         Legal Proceedings


Contingencies arising out of the Company's normal course of business existed as of September 30, 2017.2021.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitment"Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements in PartItem I.

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,1, Item 1A, "Risk Factors" of the Company's Annual Report on Form 10-K for the period ended December 31, 2016.2020.



Item 5.                      Other Information

Departure 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 appointment to the position of Controller and Principal Accounting Officer, and in addition to his current compensation package, Mr. King will participate in the Company’s Long Term Incentive Plan and other benefit programs of the Company.

Also effective November 2, 2017, the sole shareholder 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 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015.



Item 6.         Exhibits


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

66




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 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
Credit Agreement dated October 25, 2017 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).
10.2
Credit Agreement dated October 25, 2017 among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, 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).
12.1*
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, 20172021 filed on November 3, 20172021 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
__________________
*
Filed herewith.

*Filed herewith.



67


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, 20172021



5768