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, 2019March 31, 2020
OR
[  ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the Transition period from ________ to ________
Commission File Number
Exact name of registrant as specified in its charter, state of incorporation,

address of principal executive offices, telephone number
I.R.S.

Employer

Identification

Number
psd-20200331_g1.jpg
1-16305
PUGET ENERGY, INC.
A Washington Corporation
355 110th Ave NE
Bellevue, Washington 98004
(425) 454-6363
91-1969407
psd-20200331_g2.jpg
1-4393
PUGET SOUND ENERGY, INC.
A Washington Corporation
355 110th Ave NE
Bellevue, Washington 98004
(425) 454-6363
91-0374630
Securities Registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
N/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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Puget Energy, Inc.Yes/X/No/  /Puget Sound Energy, Inc.Yes/X/No/  /
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer", "accelerated filer," a smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Puget Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filer/X/Smaller reporting company/  /Emerging growth company/  /
Puget Sound Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filer/X/Smaller reporting company/  /Emerging growth company/  /
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Puget Energy, Inc.Yes/  /No/X/Puget Sound Energy, Inc.Yes/  /No/X/
All of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.  All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.



Table of Contents


Page
3
4
4
Page
6
6
Filing Format
4
Forward-Looking Statements
4
Part I.
Financial Information
5
Item 1.
Financial Statements
5
Puget Energy, Inc.
56
67
78
810
911
Puget Sound Energy, Inc.
1012
1113
1214
1416
1517
Notes
1618
3538
61
6162
6263
6263
6263
62
Exhibit Index
63
Signatures
64


DEFINITIONS

ARO
63
65

2

DEFINITIONS

AROAsset Retirement and Environmental Obligations
ASUAccounting Standards Update
ASCAccounting Standards Codification
EBITDAEarnings Before Interest, Tax, Depreciation and Amortization
EIMEnergy 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
PTCProduction Tax Credit
PSEPuget Sound Energy, Inc.
Puget EnergyPuget Energy, Inc.
Puget HoldingsPuget Holdings, LLC
Puget LNGPuget Liquid Natural Gas, LLC
REPResidential Exchange Program
SERPSupplemental Executive Retirement Plan
TCJATax Cuts and Jobs Act
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 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, including as a result of the TCJA, or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;
●Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
●Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
●The impact of widespread health developments, including the recent global coronavirus (COVID–19) pandemic, and responses to such developments (such as voluntary and mandatory quarantines, including government stay at home orders, as well as shut downs and other restrictions on travel, commercial, social and other activities) could materially and adversely affect, among other things, electric and natural gas demand, customers’ ability to pay, supply chains, availability of skilled work-force, contract counterparties, liquidity and financial markets;


●Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
●PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
●The ability to restart generation following a regional transmission disruption;
●The ability of a natural gas or electric plant to operate as intended;
●Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;
●The ability to renew contracts for electric and natural gas supply and the price of renewal;
●Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
●The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
●The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
●Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
●Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●Employee workforce factors including strikes,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.


Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.  For further information, see Item 1A, “Risk Factors” in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2018.2019.



5

PART I                    FINANCIAL INFORMATION


Item 1.                      Financial Statements


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






Three Months Ended
March 31,
20202019
Operating revenue:
Electric$669,090  $798,928  
Natural Gas371,031304,668
Other6,00911,243
Total operating revenue1,046,130  1,114,839  
Operating expenses:
Energy costs:
Purchased electricity165,742270,702
Electric generation fuel63,62477,199
Residential exchange(24,634)(25,163)
Purchased natural gas154,87699,387
Unrealized (gain) loss on derivative instruments, net48,541(15,187)
Utility operations and maintenance154,922157,955
Non-utility expense and other12,96213,757
Depreciation & Amortization164,816180,697
Conservation amortization27,39333,286
Taxes other than income taxes105,504108,746
Total operating expenses873,746  901,379  
Operating income(loss)172,384213,460
Other income (expense):
Other income14,05913,564
Other expense(2,282)(1,776)
Interest charges:
AFUDC3,6433,350
Interest expense(88,884)(88,016)
Income (loss) before income taxes98,920140,582
Income tax (benefit) expense3,9848,428
Net income (loss)$94,936  $132,154  
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Operating revenue:       
Electric$513,926
 $534,569
 $1,823,596
 $1,735,765
Natural gas108,222
 106,826
 566,347
 597,306
Other4,859
 10,069
 22,833
 28,253
Total operating revenue627,007
 651,464
 2,412,776
 2,361,324
Operating expenses: 
  
    
Energy costs: 
  
    
Purchased electricity107,035
 148,536
 501,738
 431,856
Electric generation fuel93,642
 71,004
 208,442
 143,177
Residential exchange(15,295) (15,401) (56,430) (55,436)
Purchased natural gas27,778
 30,192
 168,281
 211,679
Unrealized (gain) loss on derivative instruments, net14,716
 (14,046) 29,861
 (21,953)
Utility operations and maintenance142,857
 139,361
 450,236
 440,016
Non-utility expense and other12,436
 19,338
 36,813
 40,587
Depreciation and amortization138,281
 149,760
 483,693
 486,377
Conservation amortization17,734
 21,601
 71,049
 82,489
Taxes other than income taxes61,697
 63,822
 240,392
 248,357
Total operating expenses600,881
 614,167
 2,134,075
 2,007,149
Operating income (loss)26,126
 37,297
 278,701
 354,175
Other income (expense): 
  
    
Other income15,439
 24,806
 44,442
 46,378
Other expense(2,023) (3,250) (5,624) (7,678)
Interest charges: 
  
    
AFUDC3,732
 3,911
 10,652
 10,112
Interest expense(89,029) (87,578) (264,815) (261,988)
Income (loss) before income taxes(45,755) (24,814) 63,356
 140,999
Income tax (benefit) expense(6,312) (2,844) 3,597
 12,428
Net income (loss)$(39,443) $(21,970) $59,759
 $128,571


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

6

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




Three Months Ended
March 31,
 20202019
Net income (loss)$94,936  $132,154  
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,373 and $25, respectively5,17092
Other comprehensive income (loss)5,17092
Comprehensive income (loss)$100,106  $132,246  
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Net income (loss)$(39,443) $(21,970) $59,759
 $128,571
Other comprehensive income (loss): 
  
    
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $(297), $(741), $(247) and $(620), respectively(1,114) (2,786) (931) (2,333)
Reclassification of stranded taxes to retained earnings due to tax reform—
 —
 —
 (5,230)
Other comprehensive income (loss)(1,114) (2,786) (931) (7,563)
Comprehensive income (loss)$(40,557) $(24,756) $58,828
 $121,008

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

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



ASSETS
 September 30,
2019		 December 31,
2018
Utility plant (at original cost, including construction work in progress of $658,261 and $550,466, respectively):   
Electric plant$8,738,072
 $8,515,482
Natural gas plant3,824,045
 3,598,732
Common plant1,084,309
 1,027,023
Less: Accumulated depreciation and amortization(3,157,819) (2,832,321)
Net utility plant10,488,607
 10,308,916
Other property and investments: 
  
Goodwill1,656,513
 1,656,513
Other property and investments277,491
 244,444
Total other property and investments1,934,004
 1,900,957
Current assets: 
  
Cash and cash equivalents12,467
 37,521
Restricted cash27,659
 18,041
Accounts receivable, net of allowance for doubtful accounts of $7,608 and $8,408, respectively206,629
 338,782
Unbilled revenue145,073
 205,285
Purchased gas adjustment receivable155,711
 9,921
Materials and supplies, at average cost120,143
 116,180
Fuel and natural gas inventory, at average cost61,793
 53,351
Unrealized gain on derivative instruments14,147
 46,507
Prepaid expense and other28,502
 25,674
Power contract acquisition adjustment gain8,281
 6,114
Total current assets780,405
 857,376
Other long-term and regulatory assets: 
  
Power cost adjustment mechanism24,810
 4,735
Regulatory assets related to power contracts14,583
 16,693
Other regulatory assets717,596
 773,552
Unrealized gain on derivative instruments2,294
 2,512
Power contract acquisition adjustment gain149,126
 156,597
Operating lease right of use asset168,491
 —
Other86,841
 77,523
Total other long-term and regulatory assets1,163,741
 1,031,612
Total assets$14,366,757
 $14,098,861


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


7
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



CAPITALIZATION AND LIABILITIES
 September 30,
2019		 December 31,
2018
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 earnings652,006
 629,003
Accumulated other comprehensive income (loss), net of tax(78,133) (77,202)
Total common shareholder’s equity3,882,830
 3,860,758
Long-term debt: 
  
First mortgage bonds and senior notes4,212,000
 3,764,412
Pollution control bonds161,860
 161,860
Long-term debt2,200,900
 1,961,900
Debt discount, issuance costs and other(214,605) (215,681)
Total long-term debt6,360,155
 5,672,491
Total capitalization10,242,985
 9,533,249
Current liabilities: 
  
Accounts payable288,126
 480,069
Short-term debt69,000
 379,297
Current maturities of long-term debt

2,412
 —
Accrued expenses: 
  
  Taxes74,971
 118,112
  Salaries and wages43,488
 50,785
  Interest81,038
 70,099
Unrealized loss on derivative instruments30,504
 46,661
Power contract acquisition adjustment loss2,473
 2,547
       Operating lease liabilities15,173
 —
Other104,132
 79,312
Total current liabilities711,317
 1,226,882
Other long-term and regulatory liabilities: 
  
Deferred income taxes808,636
 789,297
Unrealized loss on derivative instruments18,222
 11,095
Regulatory liabilities710,572
 747,203
Regulatory liability for deferred income taxes952,828
 975,974
Regulatory liabilities related to power contracts157,407
 162,711
Power contract acquisition adjustment loss12,110
 14,146
       Operating lease liabilities159,913
 —
Other deferred credits592,767
 638,304
Total other long-term and regulatory liabilities3,412,455
 3,338,730
Commitments and contingencies (Note 8)

 

Total capitalization and liabilities$14,366,757
 $14,098,861



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



ASSETS
March 31, 2020December 31, 2019
Utility plant (at original cost, including construction work in progress of $649,600 and $591,199 respectively):
Electric plant$8,916,451  $8,811,889  
Natural gas plant4,000,428  3,916,040  
Common plant1,104,162  1,096,649  
Less: Accumulated depreciation and amortization(3,355,008) (3,236,240) 
Net utility plant10,666,033  10,588,338  
Other property and investments:
Goodwill1,656,5131,656,513
Other property and investments285,262286,975
Total other property and investments1,941,775  1,943,488  
Current assets:
Cash and cash equivalents10,61445,259
Restricted cash31,38820,887
Accounts receivable, net of allowance for doubtful accounts of $9,814 and $8,294, respectively320,525316,352
Unbilled revenue196,364224,657
Materials and supplies, at average cost114,612115,684
Fuel and natural gas inventory, at average cost37,58652,083
Unrealized gain on derivative instruments14,90623,626
Prepaid expense and other27,25327,504
Power contract acquisition adjustment gain10,7699,067
Total current assets764,017  835,119  
Other long-term and regulatory assets:
Power cost adjustment mechanism46,27841,745
Purchased gas adjustment receivable91,337132,766
Regulatory assets related to power contracts13,73114,146
Other regulatory assets665,927673,021
Unrealized gain on derivative instruments3,7187,682
Power contract acquisition adjustment gain91,295147,530
Operating lease right-of-use asset180,188183,048
Other89,66592,980
Total other long-term and regulatory assets1,182,1391,292,918
Total assets$14,553,964  $14,659,863  

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



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



CAPITALIZATION AND LIABILITIES
March 31, 2020December 31, 2019
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 earnings847,782  775,491  
Accumulated other comprehensive income (loss), net of tax(78,979) (84,149) 
Total common shareholder’s equity4,077,760  4,000,299  
Long-term debt:
First mortgage bonds and senior notes4,212,0004,212,000
Pollution control bonds161,860161,860
Long-term debt1,765,5001,758,100
Debt discount issuance costs and other(208,542)(211,635)
Total long-term debt5,930,8185,920,325
Total capitalization10,008,578  9,920,624  
Current liabilities:
Accounts payable279,048325,913
Short-term debt76,000176,000
Current maturities of long-term debt452,412452,412
Accrued expenses:
Taxes121,15799,979
Salaries and wages32,85350,091
Interest80,00174,855
Unrealized loss on derivative instruments41,70913,428
Power contract acquisition adjustment loss2,3322,418
Operating lease liabilities16,18315,862
Other111,538107,809
Total current liabilities1,213,233  1,318,767  
Other long-term and regulatory liabilities:
Deferred income taxes841,871824,720
Unrealized loss on derivative instruments29,50612,693
Regulatory liabilities705,212730,879
Regulatory liability for deferred income taxes939,004946,179
Regulatory liabilities related to power contracts102,064156,597
Power contract acquisition adjustment loss11,39911,728
Operating lease liabilities170,638174,327
Other deferred credits532,459563,349
Total long-term and regulatory liabilities3,332,1533,420,472
Commitments and contingencies (Note 8)
Total capitalization and liabilities$14,553,964  $14,659,863  

The accompanying notes are an integral part of the financial statements.
9

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)


Common StockAdditionalAccumulated Other
SharesAmountPaid-in capitalRetained EarningsComprehensive Income (Loss)Total Equity
Balance at December 31, 2018200$—  $3,308,957  $629,003  $(77,202) $3,860,758  
Net income (loss)———132,154—132,154
Common stock dividend paid———(35,994)—(35,994)
Other comprehensive income (loss)————9292
Balance at March 31, 2019200$—  $3,308,957  $725,163  $(77,110) $3,957,010  
Balance at December 31, 2019200$—  $3,308,957  $775,491  $(84,149) $4,000,299  
Net income (loss)———94,936—94,936
Common stock dividend paid———(22,645)—(22,645)
Other comprehensive income (loss)————5,1705,170
Balance at March 31, 2020200$—  $3,308,957  $847,782  $(78,979) $4,077,760  
 Common Stock Additional   Accumulated Other  
 Shares Amount 
Paid-in
Capital
 Retained Earnings 
Comprehensive
Income (Loss)
 
Total
Equity
Balance at December 31, 2017200
 $—
 $3,308,957
 $465,355
 $(24,282) $3,750,030
Net income (loss)—
 —
 —
 146,897
 —
 146,897
Common stock dividend paid—
 —
 —
 (30,096) —
 (30,096)
Other comprehensive income (loss)—
 —
 —
 —
 (5,003) (5,003)
Cumulative effect of accounting change—
 —
 —
 5,230
 —
 5,230
Balance at March 31, 2018200
 $—
 $3,308,957
 $587,386
 $(29,285) $3,867,058
Net income (loss)—
 —
 —
 3,642
 $—
 3,642
Common stock dividend paid—
 —
 —
 (25,429) $—
 (25,429)
Other comprehensive income (loss)—
 —
 —
 —
 226
 226
Balance at June 30, 2018200
 $—
 $3,308,957
 $565,599
 $(29,059) $3,845,497
Net income (loss)—
 —
 —
 (21,970) —
 (21,970)
Common stock dividend paid—
 —
 —
 (21,202) —
 (21,202)
Other comprehensive income (loss)—
 —
 —
 —
 (2,786) (2,786)
Balance at September 30, 2018200
 $—
 $3,308,957
 $522,427
 $(31,845) $3,799,539
Balance at December 31, 2018200
 $—
 $3,308,957
 $629,003
 $(77,202) $3,860,758
Net income (loss)—
 —
 —
 132,154
 —
 132,154
Common stock dividend paid—
 —
 —
 (35,994) —
 (35,994)
Other comprehensive income (loss)—
 —
 —
 —
 92
 92
Balance at March 31, 2019200
 $—
 $3,308,957
 $725,163
 $(77,110) $3,957,010
Net income (loss)  —
 —
 (32,952) —
 (32,952)
Common stock dividend paid  —
 —
 (83) —
 (83)
Other comprehensive income (loss)  —
 —
 —
 91
 91
Balance at June 30, 2019200
 $—
 $3,308,957
 $692,128
 $(77,019) $3,924,066
Net income (loss)—
 —
 —
 (39,443) —
 (39,443)
Common stock dividend paid—
 —
 —
 (679) —
 (679)
Other comprehensive income (loss)—
 —
 —
 —
 (1,114) (1,114)
Balance at September 30, 2019200
 $—
 $3,308,957
 $652,006
 $(78,133) $3,882,830



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





10
 PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 Nine Months Ended September 30,
 2019 2018
Operating activities:   
Net income (loss)$59,759
 $128,571
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
Depreciation and amortization483,693
 486,377
Conservation amortization71,049
 82,489
Deferred income taxes and tax credits, net(3,559) 5,554
Net unrealized (gain) loss on derivative instruments29,861
 (21,953)
AFUDC – equity(10,071) (12,958)
Production tax credit monetization(35,470) (56,177)
Other non-cash1,712
 11,105
Funding of pension liability(18,000) (13,500)
Regulatory assets and liabilities(46,993) (22,545)
Other long-term assets and liabilities(3,075) (4,872)
Change in certain current assets and liabilities: 
  
Accounts receivable and unbilled revenue192,365
 214,166
Materials and supplies(3,963) (7,002)
Fuel and natural gas inventory(8,442) (7,385)
Prepayments and other(2,283) (15,763)
Purchased gas adjustment(145,790) 19,911
Accounts payable(160,792) (38,001)
Taxes payable(43,141) 6,695
Other(2,727) (12,379)
Net cash provided by (used in) operating activities354,133
 742,333
Investing activities: 
  
Construction expenditures – excluding equity AFUDC(709,139) (760,728)
Other(5,914) 2,090
Net cash provided by (used in) investing activities(715,053) (758,638)
Financing activities: 
  
Change in short-term debt, net(310,297) (123,463)
Dividends paid(36,756) (76,728)
Proceeds from long-term debt and bonds issued682,151
 642,615
Redemption of bonds and notes—
 (450,000)
Other10,386
 6,228
Net cash provided by (used in) financing activities345,484
 (1,348)
Net increase (decrease) in cash, cash equivalents, and restricted cash(15,436) (17,653)
Cash, cash equivalents, and restricted cash at beginning of period55,562
 36,761
Cash, cash equivalents, and restricted cash at end of period$40,126
 $19,108
Supplemental cash flow information: 
  
Cash payments for interest (net of capitalized interest)$236,718
 $234,438
Cash payments (refunds) for income taxes$8,990
 $7,595
Non-cash financing and investing activities:   
Accounts payable for capital expenditures eliminated from cash flows$65,023
 $105,070
Reclassification of Colstrip from utility plant to a regulatory asset (Note 8)$(47,534) $—



PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Three Months Ended
March 31,
20202019
Operating activities:
Net Income (loss)$94,936  $132,154  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization164,816180,697
Conservation amortization27,39333,286
Deferred income taxes and tax credits, net8,60211,401
Net unrealized (gain) loss on derivative instruments48,541(15,187)
AFUDC - equity(5,603)(3,597)
Production tax credit utilization(23,543)(27,131)
Other non-cash(6,075)3,722
Regulatory assets and liabilities(16,865)(15,838)
Purchased gas adjustment41,429(137,092)
Other long term assets and liabilities(27,016)(13,463)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue24,120(24,413)
Materials and supplies1,072(4,063)
Fuel and natural gas inventory14,49713,190
Prepayments and other251(5,964)
Purchased gas adjustment—9,921
Accounts payable(45,236)45,827
Taxes payable21,17811,140
Other(11,126)3,607
Net cash provided by (used in) operating activities311,371  198,197  
Investing activities:
Construction expenditures - excluding equity AFUDC(223,707)(227,807)
Other(233)264
Net cash provided by (used in) investing activities(223,940) (227,543) 
Financing activities:
Change in short-term debt, net(100,000)52,703
Dividends paid(22,645)(35,994)
Proceeds from long-term debt and bonds issued7,40013,400
Other3,6706,714
Net cash provided by (used in) financing activities(111,575)36,823
Net increase (decrease) in cash, cash equivalents, and restricted cash(24,144)7,477
Cash, cash equivalents, and restricted cash at beginning of period66,14655,562
Cash, cash equivalents, and restricted cash at end of period$42,002  $63,039  
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$78,636  $46,036  
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$56,699  $77,400  

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





11


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




Three Months Ended
March 31,
20202019
Operating revenue:
Electric$669,090  $798,928  
Natural Gas371,031304,668
Other6,00911,243
Total operating revenue1,046,1301,114,839
Operating expenses:
Energy costs:
Purchased electricity165,742270,702
Electric generation fuel63,62477,199
Residential exchange(24,634)(25,163)
Purchased natural gas154,87699,387
Unrealized (gain) loss on derivative instruments, net48,541(15,187)
Utility operations and maintenance154,922157,955
Non-utility expense and other12,73513,077
Depreciation & Amortization164,771180,678
Conservation amortization27,39333,286
Taxes other than income taxes105,504108,746
Total operating expenses873,474900,680
Operating income(loss)172,656214,159
Other income (expense):
Other income11,28310,549
Other expense(2,282)(1,776)
Interest charges:
AFUDC3,6433,350
Interest expense(60,714)(60,150)
Income (loss) before income taxes124,586166,132
Income tax (benefit) expense13,26518,830
Net income (loss)$111,321  $147,302  
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Operating revenue:       
Electric$513,926
 $534,569
 $1,823,596
 $1,735,765
Natural gas108,222
 106,826
 566,347
 597,306
Other4,859
 10,069
 22,833
 28,253
Total operating revenue627,007
 651,464
 2,412,776
 2,361,324
Operating expenses: 
  
    
Energy costs: 
  
    
Purchased electricity107,035
 148,536
 501,738
 431,856
Electric generation fuel93,642
 71,004
 208,442
 143,177
Residential exchange(15,295) (15,401) (56,430) (55,436)
Purchased natural gas27,778
 30,192
 168,281
 211,679
Unrealized (gain) loss on derivative instruments, net14,716
 (14,046) 29,861
 (21,953)
Utility operations and maintenance142,857
 139,361
 450,236
 440,016
Non-utility expense and other11,869
 10,518
 34,924
 31,132
Depreciation and amortization138,253
 149,730
 483,623
 486,300
Conservation amortization17,734
 21,601
 71,049
 82,489
Taxes other than income taxes61,697
 63,822
 240,392
 248,357
Total operating expenses600,286
 605,317
 2,132,116
 1,997,617
Operating income (loss)26,721
 46,147
 280,660
 363,707
Other income (expense): 
  
    
Other income12,373
 13,596
 35,334
 29,352
Other expense(2,023) (3,250) (5,624) (7,678)
Interest charges: 
  
    
AFUDC3,732
 3,911
 10,652
 10,112
Interest expense(61,145) (58,278) (181,230) (174,853)
Income (loss) before income taxes(20,342) 2,126
 139,792
 220,640
Income tax (benefit) expense(5,085) (1,765) 16,072
 26,931
Net income (loss)$(15,257) $3,891
 $123,720
 $193,709




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

12


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




Three Months Ended
March 31,
 20202019
Net income (loss)$111,321  $147,302  
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,047 and $668, respectively7,7102,510
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $26, respectively9696
Other comprehensive income (loss)7,8062,606
Comprehensive income (loss)$119,127  $149,908  
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Net income (loss)$(15,257) $3,891
 $123,720
 $193,709
Other comprehensive income (loss): 
  
    
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $357, $(30), $1,692 and $1,492, respectively1,340
 (113) 6,362
 5,613
Amortization of treasury interest rate swaps to earnings, net of tax of $27, $26, $78 and $77, respectively97
 96
 289
 289
Reclassification of stranded taxes to retained earnings due to tax reform—
 —
 —
 (27,333)
Other comprehensive income (loss)1,437
 (17) 6,651
 (21,431)
Comprehensive income (loss)$(13,820) $3,874
 $130,371
 $172,278


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

13

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






ASSETS
March 31, 2020December 31, 2019
Utility plant (at original cost, including construction work in progress of $649,600 and $591,199 respectively):
Electric plant$10,768,636  $10,671,328  
Natural Gas plant4,561,810  4,478,048  
Common plant1,128,888  1,121,568  
Less:  Accumulated depreciation and amortization(5,793,301) (5,682,606) 
Net utility plant10,666,033  10,588,338  
Other property and investments:
Other property and investments80,929  81,112  
Total other property and investments80,929  81,112  
Current assets:
Cash and cash equivalents9,433  44,004  
Restricted cash31,388  20,887  
Accounts receivable, net of allowance for doubtful accounts of $9,814 and $8,294, respectively321,630  319,229  
Unbilled revenue196,364  224,657  
Materials and supplies, at average cost114,612  115,684  
Fuel and natural gas inventory, at average cost36,321  50,818  
Unrealized gain on derivative instruments14,906  23,626  
Prepaid expense and other27,253  27,504  
Total current assets751,907  826,409  
Other long-term and regulatory assets:
Power cost adjustment mechanism46,278  41,745  
Purchased gas adjustment receivable91,337  132,766  
Other regulatory assets665,927  673,021  
Unrealized gain on derivative instruments3,718  7,682  
Operating lease right-of-use asset180,188  183,048  
Other87,743  90,924  
Total other long-term and regulatory assets1,075,191  1,129,186  
Total assets$12,574,060  $12,625,045  
 September 30,
2019		 December 31,
2018
Utility plant (at original cost, including construction work in progress of $658,261 and $550,466, respectively):   
Electric plant$10,797,117
 $10,587,231
Natural gas plant4,386,972
 4,164,489
Common plant1,109,251
 1,052,544
Less:  Accumulated depreciation and amortization(5,804,733) (5,495,348)
Net utility plant10,488,607
 10,308,916
Other property and investments: 
  
Other property and investments81,013
 76,986
Total other property and investments81,013
 76,986
Current assets: 
  
Cash and cash equivalents10,929
 35,452
Restricted cash27,659
 18,041
Accounts receivable, net of allowance for doubtful accounts of $7,608 and $8,408, respectively209,586
 346,251
Unbilled revenue145,073
 205,285
Purchased gas adjustment receivable155,711
 9,921
Materials and supplies, at average cost120,143
 116,180
Fuel and natural gas inventory, at average cost60,470
 52,028
Unrealized gain on derivative instruments14,147
 46,507
Prepaid expense and other28,502
 25,674
Total current assets772,220
 855,339
Other long-term and regulatory assets: 
  
Power cost adjustment mechanism24,810
 4,735
Other regulatory assets717,596
 773,552
Unrealized gain on derivative instruments2,294
 2,512
Operating lease right of use asset168,491
 —
Other84,651
 75,483
Total other long-term and regulatory assets997,842
 856,282
Total assets$12,339,682
 $12,097,523


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

14


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




CAPITALIZATION AND LIABILITIES


March 31, 2020December 31, 2019
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding$859  $859  
Additional paid-in capital3,485,105  3,485,105  
Retained earnings808,720  751,193  
Accumulated other comprehensive income (loss), net of tax(180,671) (188,477) 
Total common shareholder’s equity4,114,013  4,048,680  
Long-term debt:
First mortgage bonds and senior notes4,212,000  4,212,000  
Pollution control bonds161,860  161,860  
Debt discount, issuance costs and other(37,248) (37,718) 
Total long-term debt4,336,612  4,336,142  
Total capitalization8,450,625  8,384,822  
Current liabilities:
Accounts payable288,150  325,980  
Short-term debt76,000  176,000  
Current maturities of long-term debt2,412  2,412  
Accrued expenses:
Taxes126,827  99,977  
Salaries and wages32,853  50,091  
Interest57,582  48,917  
Unrealized loss on derivative instruments41,709  13,428  
Operating lease liabilities16,183  15,862  
Other111,538  107,809  
Total current liabilities753,254  840,476  
Other long-term and regulatory liabilities:
Deferred income taxes998,630  977,163  
Unrealized loss on derivative instruments29,506  12,693  
Regulatory liabilities703,947  729,614  
Regulatory liabilities for deferred income tax939,759  946,936  
Operating lease liabilities170,638  174,327  
Other deferred credits527,701  559,014  
Total long-term and regulatory liabilities3,370,181  3,399,747  
Commitments and contingencies (Note 8)
Total capitalization and liabilities$12,574,060  $12,625,045  
 September 30,
2019		 December 31,
2018
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
 3,275,105
Retained earnings632,702
 622,844
Accumulated other comprehensive income (loss), net of tax(184,233) (190,884)
Total common shareholder’s equity3,934,433
 3,707,924
Long-term debt: 
  
First mortgage bonds and senior notes4,212,000
 3,764,417
Pollution control bonds161,860
 161,860
Debt discount, issuance costs and other(38,067) (31,417)
Total long-term debt4,335,793
 3,894,860
Total capitalization8,270,226
 7,602,784
Current liabilities: 
  
Accounts payable288,194
 480,195
Short-term debt69,000
 379,297
Current maturities of long-term debt2,412
 —
Accrued expenses: 
  
Taxes77,815
 117,993
Salaries and wages43,488
 50,785
Interest58,410
 43,951
       Unrealized loss on derivative instruments30,504
 46,661
       Operating lease liabilities15,173
 —
       Other104,132
 79,312
Total current liabilities689,128
 1,198,194
Other long-term and regulatory liabilities: 
  
Deferred income taxes949,526
 926,403
Unrealized loss on derivative instruments18,222
 11,095
Regulatory liabilities709,249
 745,880
Regulatory liability for deferred income taxes953,627
 976,582
Operating lease liabilities159,913
 —
Other deferred credits589,791
 636,585
Total other long-term and regulatory liabilities3,380,328
 3,296,545
Commitments and contingencies (Note 8)

 

Total capitalization and liabilities$12,339,682
 $12,097,523



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

15

 PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(Dollars in Thousands)
(Unaudited)


Common StockAdditionalAccumulated Other
SharesAmountPaid-in capitalRetained EarningsComprehensive Income (Loss)Total Equity
Balance at December 31, 201885,903,791$859  $3,275,105  $622,844  $(190,884) $3,707,924  
Net income (loss)——  —  147,302  —  147,302  
Common stock dividend paid——  —  (64,604) —  (64,604) 
Other comprehensive income (loss)——  —  —  2,606  2,606  
Balance at March 31, 201985,903,791$859  $3,275,105  $705,542  $(188,278) $3,793,228  
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  
 Common Stock Additional   Accumulated Other  
 Shares Amount 
Paid-in
Capital
 Retained Earnings 
Comprehensive
Income (loss)
 
Total
Equity
Balance at December 31, 2017$85,903,791
 $859
 $3,275,105
 $452,066
 $(126,906) $3,601,124
Net income (loss)—
 —
 —
 163,037
 —
 163,037
Common stock dividend paid—
 —
 —
 (58,612) —
 (58,612)
Other comprehensive income (loss)—
 —
 —
 —
 (24,374) (24,374)
Cumulative effect of accounting change—
 —
 —
 27,333
 —
 27,333
Balance at March 31, 2018$85,903,791
 $859
 $3,275,105
 $583,824
 $(151,280) $3,708,508
Net income (loss)—
 —
 —
 26,778
 —
 26,778
Common stock dividend paid—
 —
 —
 (43,844) —
 (43,844)
Other comprehensive income (loss)—
 —
 —
 —
 2,960
 2,960
Balance at June 30, 2018$85,903,791
 $859
 $3,275,105
 $566,758
 $(148,320) $3,694,402
Net income (loss)—
 —
 —
 3,891
 —
 3,891
Common stock dividend paid—
 —
 —
 (48,857) —
 (48,857)
Other comprehensive income (loss)—
 —
 —
 —
 (17) (17)
Balance at September 30, 2018$85,903,791
 $859
 $3,275,105
 $521,792
 $(148,337) $3,649,419
Balance at December 31, 2018$85,903,791
 $859
 $3,275,105
 $622,844
 $(190,884) $3,707,924
Net income (loss)—
 —
 —
 147,302
 —
 147,302
Common stock dividend paid—
 —
 —
 (64,604) —
 (64,604)
Other comprehensive income (loss)—
 —
 —
 —
 2,606
 2,606
Balance at March 31, 2019$85,903,791
 $859
 $3,275,105
 $705,542
 $(188,278) $3,793,228
Net income (loss)—
 —
 —
 (8,325) —
 (8,325)
Common stock dividend paid—
 —
 —
 (19,384) —
 (19,384)
Other comprehensive income (loss)—
 —
 —
 —
 2,608
 2,608
Balance at June 30, 2019$85,903,791
 $859
 $3,275,105
 $677,833
 $(185,670) $3,768,127
Net income (loss)—
 —
 —
 (15,257) —
 (15,257)
Common stock dividend paid—
 —
 —
 (29,874) —
 (29,874)
Capital Contribution—
 —
 210,000
 —
 —
 210,000
Other comprehensive income (loss)—
 —
 —
 —
 1,437
 1,437
Balance at September 30, 2019$85,903,791
 $859
 $3,485,105
 $632,702
 $(184,233) $3,934,433


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





16

PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Three Months Ended
March 31,
20202019
Operating activities:
Net Income (loss)$111,321  $147,302  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization164,771  180,678  
Conservation amortization27,393  33,286  
Deferred income taxes and tax credits, net12,215  19,293  
Net unrealized (gain) loss on derivative instruments48,541  (15,187) 
AFUDC - equity(5,603) (3,597) 
Production tax credit utilization(23,543) (27,131) 
Other non-cash(8,711) 1,109  
Regulatory assets and liabilities(16,865) (15,838) 
Purchased gas adjustment41,429  (137,092) 
Other long term assets and liabilities(23,801) (11,959) 
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue25,892  (19,711) 
Materials and supplies1,072  (4,063) 
Fuel and natural gas inventory14,497  13,190  
Prepayments and other251  (5,964) 
Purchased gas adjustment—  9,921  
Accounts payable(36,201) 45,714  
Taxes payable26,850  13,650  
Other(7,607) 8,006  
Net cash provided by (used in) operating activities351,901  231,607  
Investing activities:
Construction expenditures - excluding equity AFUDC(225,612) (218,006) 
Other(233) 264  
Net cash provided by (used in) investing activities(225,845) (217,742) 
Financing activities:
Change in short-term debt, net(100,000) 52,703  
Dividends paid(53,794) (64,604) 
Other3,668  6,712  
Net cash provided by (used in) financing activities(150,126) (5,189) 
Net increase (decrease) in cash, cash equivalents, and restricted cash(24,070) 8,676  
Cash, cash equivalents, and restricted cash at beginning of period64,891  53,493  
Cash, cash equivalents, and restricted cash at end of period$40,821  $62,169  
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)$47,115  $43,181  
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows$56,699  $77,400  
 Nine Months Ended September 30,
 2019 2018
Operating activities:   
Net income (loss)$123,720
 $193,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
Depreciation and amortization483,623
 486,300
Conservation amortization71,049
 82,489
Deferred income taxes and tax credits, net(1,600) 12,801
Net unrealized (gain) loss on derivative instruments29,861
 (21,953)
AFUDC – equity(10,071) (12,958)
Production tax credit monetization(35,470) (56,177)
Other non-cash(6,167) 3,319
Funding of pension liability(18,000) (13,500)
Regulatory assets and liabilities(46,993) (22,545)
Other long-term assets and liabilities4,972
 5,144
Change in certain current assets and liabilities: 
  
Accounts receivable and unbilled revenue196,877
 208,359
Materials and supplies(3,963) (7,002)
Fuel and natural gas inventory(8,442) (7,385)
Prepayments and other(2,283) (15,763)
Purchased gas adjustment(145,790) 19,911
Accounts payable(160,850) (37,988)
Taxes payable(40,178) 7,580
Other794
 (9,528)
Net cash provided by (used in) operating activities431,089
 814,813
Investing activities: 
  
Construction expenditures – excluding equity AFUDC(680,118) (712,329)
Other(5,916) 2,090
Net cash provided by (used in) investing activities(686,034) (710,239)
Financing activities: 
  
Change in short-term debt, net(310,297) (123,463)
Dividends paid(113,862) (151,315)
Long-term bonds and notes issued443,151
 594,750
Redemption of bonds and notes—
 (450,000)
Investment from parent210,000
 —
Other11,048
 6,228
Net cash provided by (used in) financing activities240,040
 (123,800)
Net increase (decrease) in cash, cash equivalents, and restricted cash(14,905) (19,226)
Cash, cash equivalents, and restricted cash at beginning of period53,493
 36,009
Cash, cash equivalents, and restricted cash at end of period$38,588
 $16,783
Supplemental cash flow information: 
  
Cash payments for interest (net of capitalized interest)$152,571
 $152,273
Cash payments (refunds) for income taxes$16,540
 $13,839
Non-cash financing and investing activities:   
Accounts payable for capital expenditures eliminated from cash flows$65,023
 $105,070
Reclassification of Colstrip from utility plant to a regulatory asset (Note 8)$(47,534) $—


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

17

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)




(1)Summary of Consolidation and Significant Accounting 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, Puget LNG, LLC, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.
In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with FASB ASC 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial information furnished herein reflectsstatements are presented after elimination of all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All significant intercompany accountsitems and transactions are eliminated in consolidation.transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.


Allowance for Credit Losses
On January 1, 2020, the Company adopted ASU 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables.
The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial.
Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts.
The following table presents the activity in the allowance for credit losses for accounts receivable for the quarter ended March 31, 2020:
March 31, 2020
Allowance for credit losses:
Beginning balance$8,294 
Provision for credit loss expense4,894 
Receivables charged-off(3,374)
Total ending allowance balance$9,814 


18

Tacoma LNG Facility
In August 2015, PSE filed a proposal with the Washington Utilities and Transportation Commission (Washington Commission) to develop an LNG facility at the Port of Tacoma.
Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility
is intendeddesigned to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet
the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) iswas 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 may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit.was impacted. PSE received the SEIS which concluded the LNG facility would result in a net
decrease in GHG emissions providedproviding, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. PSE must now awaitOn December 10, 2019, the final determinationPSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by PSCAA.each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice.
If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $191.8$198.0 million and $199.9 million of construction work in progress and $1.0 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility areis reported in the Puget Energy "Other property and investments" line item as of March 31, 2020 and December 31, 2019, respectively. Additionally, $0.3 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line items, respectively, asitem for each of September 30, 2019.the three months ended March 31, 2020, and March 31, 2019, respectively. Additionally, $156.1$173.5 million and $162.8 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of March 31, 2020 and December 31, 2019, respectively, as PSE is a regulated entity.


Leases
PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets.

ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.
PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

(2)  New Accounting Pronouncements

Recently Adopted Accounting Guidance
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 ROU lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB ASC and created Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a ROU asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.
In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842". In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company elected this practical expedient.
In July 2018, the FASB issued both ASU 2018-10 and ASU 2018-11, "Leases (Topic 842): Codification Improvements" and "Leases (Topic 842): Targeted Improvements". These ASUs provide entities with both clarification on existing guidance issued in ASU 2016-02, as well as an additional transition method to adopt the new leasing standard. Under the new transition method, the entity initially applies the new standard at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements will continue to be in accordance with Topic 840. The Company has elected to adopt the standard using this new modified transition method.
In preparation for adoption of the standard, the Company assembled a project team that met bi-weekly to make key accounting assessments and perform pre-implementation controls related to the scoping and completeness of existing leases. Additionally, the Company implemented a new leasing system and drafted accounting policies including discount rate, variable pricing, power purchase agreements, and election of practical expedients. In addition to the land easement practical expedient, the Company has elected the practical expedient package.
These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has adopted ASU 2016-02 as of January 1, 2019, which resulted in the recognition of ROU asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the income statement. The financial impact as of the date of adoption was not materially different than what has been disclosed as of September 30, 2019, in Note 9, "Leases", to the consolidated financial statements included in Item 1 of this report.


Internal-Use Software
In August 2018, the FASB issued ASU 2018-15, "Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract". These amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The accounting for the service element of a hosting arrangement that is a service contract is not affected by these amendments.
The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted, including adoption in any interim period, for all entities. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company adopted this update prospectively in 2019 for implementation costs incurred in hosting arrangements and application of the amendment has not had a material impact on the consolidated financial statements.

Accounting Standards Issued but Not Yet Adopted
Credit Losses
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables. It also applies to off-balance sheet credit exposures not accounted for as insurance and net investments in leases recognized by a lessor in accordance with Topic 842.
The Company is currently evaluatingadopted ASC 326 using the modified retrospective method for all financial assets measured at amortized cost. Results for reporting periods beginning after January 1, 2020, are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact of adoption ofwas immaterial and the new standard on its consolidated financial statements.Company did not record a transition adjustment to retained earnings.


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

Reference Rate Reform
In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the consolidatedcurrent guidance on contract modifications to ease the financial statements.reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of March 31, 2020, the Company has not utilized any of the

19

expedients discussed within this ASU, however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022.

Accounting Standards Issued but Not Yet Adopted
Retirement Benefits
In August 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures.
The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities.Accordingly, the Company will implement this update as of December 31, 2020. The Company is in the process of evaluating potential impacts of these amendments to Note 6, "Retirement Benefits", to the consolidated financial statements.required annual retirement benefits disclosures.



(3) Revenue


The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:
Puget Energy and
Puget Sound Energy
       Puget Energy and
Puget Sound Energy
(Dollars in Thousands)Three Months Ended
September 30,		 Nine Months Ended
September 30,		(Dollars in Thousands)Three Months Ended
March 31,
Revenue from contracts with customers:2019 2018 2019 2018Revenue from contracts with customers:20202019
Electric retail$450,109
 $464,210
 $1,550,517
 $1,563,394
Electric retail$607,693  $637,189  
Natural gas retail101,395
 101,995
 569,177
 594,572
Natural gas retail365,637  322,560  
Other72,691
 67,217
 245,285
 148,581
Other43,774  135,696  
Total revenue from contracts with customers624,195
 633,422
 2,364,979
 2,306,547
Total revenue from contracts with customers1,017,104  1,095,445  
Alternative revenue programs874
 (782) (20,006) (24,678)Alternative revenue programs1,150  (25,231) 
Other non-customer revenue1,938
 18,824
 67,803
 79,455
Other non-customer revenue27,876  44,625  
Total operating revenue$627,007
 $651,464
 $2,412,776
 $2,361,324
Total operating revenue$1,046,130  $1,114,839  


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


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


20

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


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


Biogas Revenue
Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon

PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.


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


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


(4) Accounting for Derivative Instruments and Hedging Activities


PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.
PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.



21

The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:
Puget Energy and
Puget Sound Energy
        Puget Energy and
Puget Sound Energy
At September 30, 2019 December 31, 2018March 31, 2020December 31, 2019
(Dollars in Thousands)Volumes 
Assets1
 
Liabilities2
 Volumes 
Assets1
 
Liabilities2
(Dollars in Thousands)Volumes
Assets1
Liabilities2
Volumes
Assets1
Liabilities2
Electric portfolio derivatives* $9,483
 $33,341
 * $33,287
 $27,284
Electric portfolio derivatives*$11,028  $57,140  *$19,933  $17,504  
Natural gas derivatives (MMBtus)3
288.3 million 6,958
 15,385
 336.6 million 15,732
 30,472
Natural gas derivatives (MMBtus)3
292.1 million7,596  14,075  315.5 million11,375  8,617  
Total derivative contracts  $16,441
 $48,726
   $49,019
 $57,756
Total derivative contracts$18,624  $71,215  $31,308  $26,121  
Current  $14,147
 $30,504
 $46,507
 $46,661
Current$14,906  $41,709  $23,626  $13,428  
Long-term 2,294
 18,222
 2,512
 11,095
Long-term3,718  29,506  7,682  12,693  
Total derivative contracts $16,441
 $48,726
 $49,019
 $57,756
Total derivative contracts$18,624  $71,215  $31,308  $26,121  
_______________
1
Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.
2
Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
3
All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
*
Electric portfolio derivatives consist of electric generation fuel of 183.6 million One Million British Thermal Units (MMBtu) and purchased electricity of 11.9 million Megawatt Hours (MWhs) at September 30, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018.

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 230.8 million One Million British Thermal Units (MMBtu) and purchased electricity of
8.2 million Megawatt Hours (MWhs) at March 31, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report.
The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
Puget Energy and
Puget Sound Energy
At March 31, 2020
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$18,624  $—  $18,624  $(16,598) $—  $2,026  
Liabilities:
Energy derivative contracts$71,215  $—  $71,215  $(16,598) $2,000  $56,617  

22

Puget Energy and
Puget Sound Energy
        
 At September 30, 2019
 
Gross Amount Recognized in the Statement of Financial Position1
 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position  

(Dollars in Thousands)
 Commodity Contracts Cash Collateral Received/Posted Net Amount
Assets:           
Energy derivative contracts$16,441
 $—
 $16,441
 $(14,148) $—
 $2,293
Liabilities:           
Energy derivative contracts48,726
 —
 48,726
 (14,148) (5,379) 29,199


        
Puget Energy and
Puget Sound Energy
At December 31, 2018Puget Energy and
Puget Sound Energy		At December 31, 2019
Gross Amount Recognized in the Statement of Financial Position1
 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position  
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 Contracts Cash Collateral Received/Posted Net Amount(Dollars in Thousands)Commodity ContractsCash Collateral Received/PostedNet Amount
Assets:           Assets:
Energy derivative contracts$49,019
 $—
 $49,019
 $(25,388) $—
 $23,631
Energy derivative contracts$31,308  $—  $31,308  $(14,922) $—  $16,386  
Liabilities:           Liabilities:
Energy derivative contracts57,756
 —
 57,756
 (25,388) —
 32,368
Energy derivative contracts$26,121  $—  $26,121  $(14,922) $2,000  $13,199  
_______________
1
All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.

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

The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:
Puget Energy and
Puget Sound Energy		Three Months Ended
March 31,
(Dollars in Thousands)Classification20202019
Gas for Power Derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net$(9,755) $14,961  
RealizedElectric generation fuel1,296  13,328  
Power Derivatives:
UnrealizedUnrealized gain (loss) on derivative instruments, net(38,786) 226  
RealizedPurchased electricity(5,935) 36,292  
Total gain (loss) recognized in income on derivatives$(53,180) $64,807  
Puget Energy and
Puget Sound Energy		 Three Months Ended
September 30,		 Nine Months Ended
September 30,
(Dollars in Thousands)Classification2019 2018 2019 2018
Gas for Power Derivatives:    
    
UnrealizedUnrealized gain (loss) on derivative instruments, net$8,143
 $8,503
 $5,914
 $16,172
RealizedElectric generation fuel(7,514) (6,308) 4,481
 (18,401)
Power Derivatives:        
UnrealizedUnrealized gain (loss) on derivative instruments, net(22,859) 5,543
 (35,775) 5,781
RealizedPurchased electricity(335) (4,803) 40,918
 (10,028)
Total gain (loss) recognized in income on derivatives $(22,565) $2,935
 $15,538
 $(6,476)



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, 2019,March 31, 2020, approximately 97.8%97.3% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 2.2%2.7% 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
23

reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2019,March 31, 2020, PSE had cash posted as collateral of $17.1$18.5 million related to contracts executed on the ICE platform. Also, as of September 30, 2019,March 31, 2020, PSE had $1.0$6.2 million in a letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the ninethree months ended September 30, 2019.March 31, 2020.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:
Puget Energy and
Puget Sound Energy
           Puget Energy and
Puget Sound Energy
(Dollars in Thousands)At September 30, 2019 At December 31, 2018(Dollars in Thousands)At March 31, 2020At December 31, 2019
Fair Value1
 Posted Contingent 
Fair Value1
 Posted Contingent
Fair Value1
PostedContingent
Fair Value1
PostedContingent
Contingent FeatureLiability Collateral Collateral Liability Collateral CollateralContingent FeatureLiabilityCollateralCollateralLiabilityCollateralCollateral
Credit rating2
$12,147
 $—
 $12,147
 $574
 $—
 $574
Credit rating2
$30,427  $—  $30,427  $6,110  $—  $6,110  
Requested credit for adequate assurance5,447
 —
 —
 18,495
 —
 —
Requested credit for adequate assurance6,107  —  —  5,253  —  —  
Forward value of contract3
5,379
 17,117
 —
 —
 —
 —
Forward value of contract3
10,143  —  N/A—  14,827  N/A
Total$22,973
 $17,117
 $12,147
 $19,069
 $—
 $574
Total$46,677  $—  $30,427  $11,363  $14,827  $6,110  
_______________
1
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
2
Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3
Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

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
(5)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 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.


24

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.
The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.


Assets and Liabilities with Estimated Fair Value
The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $51.1 million and $49.5$51.5 million at September 30, 2019both March 31, 2020 and December 31, 2018, respectively,2019, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
The fair value of the 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 EnergyAt March 31, 2020At December 31, 2019
(Dollars in Thousands)LevelCarrying
Value		Fair
Value		Carrying
Value		Fair
Value
Liabilities:
Long-term debt (fixed-rate), net of discount1
2$5,515,318  $6,930,219  $5,512,225  $7,004,316  
Long-term debt (variable-rate)2415,500  415,500  408,100  408,100  
Total liabilities$5,930,818  $7,345,719  $5,920,325  $7,412,416  
Puget Energy At September 30, 2019 At December 31, 2018
(Dollars in Thousands)Level
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Liabilities:        
Long-term debt (fixed-rate), net of discount1
2$5,961,667
 $7,544,799
 $5,510,591
 $6,443,742
Long-term debt (variable-rate)2400,900
 400,900
 161,900
 161,900
Total liabilities $6,362,567
 $7,945,699
 $5,672,491
 $6,605,642


Puget Sound Energy At September 30, 2019 At December 31, 2018Puget Sound EnergyAt March 31, 2020At December 31, 2019
(Dollars in Thousands)LevelCarrying
Value		 Fair
Value		 Carrying
Value		 Fair
Value		(Dollars in Thousands)LevelCarrying
Value		Fair
Value		Carrying
Value		Fair
Value
Liabilities:        Liabilities:
Long-term debt (fixed-rate), net of discount2
2$4,338,205
 $5,642,813
 $3,894,860
 $4,574,611
Long-term debt (fixed-rate), net of discount2
2$4,336,612  $5,563,257  $4,336,142  $5,571,818  
Total liabilities $4,338,205
 $5,642,813
 $3,894,860
 $4,574,611
Total liabilities$4,336,612  $5,563,257  $4,336,142  $5,571,818  
_______________
1
1 The carrying value includes debt issuances costs of $23.3 million and $24.1 million for March 31, 2020 and December 31, 2019, respectively, which are not included in fair value.
2 The carrying value includes debt issuances costs of $24.0 million and $24.4 million for March 31, 2020 and December 31, 2019, respectively, which are not included in fair value.

25

The carrying value includes debt issuances costs of $24.8 million and $26.1 million for September 30, 2019 and December 31, 2018, respectively, which are not included in fair value.
2
The carrying value includes debt issuances costs of $24.6 million and $24.6 million for September 30, 2019 and December 31, 2018, respectively, which are not included in fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
Puget Energy and
Puget Sound Energy		Fair Value
At March 31. 2020		Fair Value
At December 31, 2019
(Dollars in Thousands)Level 2Level 3TotalLevel 2Level 3Total
Assets:      
Electric derivative instruments$10,525  $503  $11,028  $19,282  $651  $19,933  
Natural gas derivative instruments6,321  1,275  7,596  9,852  1,523  11,375  
Total assets$16,846  $1,778  $18,624  $29,134  $2,174  $31,308  
Liabilities:      
Electric derivative instruments$30,331  $26,809  $57,140  $13,474  $4,030  $17,504  
Natural gas derivative instruments13,892  183  14,075  8,376  241  8,617  
Total liabilities$44,223  $26,992  $71,215  $21,850  $4,271  $26,121  
Puget Energy and
Puget Sound Energy
Fair Value
At September 30. 2019
 
Fair Value
At December 31, 2018
(Dollars in Thousands)Level 2 Level 3 Total Level 2 Level 3 Total
Assets:           
Electric derivative instruments$8,612
 $871
 $9,483
 $28,765
 $4,522
 $33,287
Natural gas derivative instruments5,279
 1,679
 6,958
 12,247
 3,485
 15,732
Total assets$13,891
 $2,550
 $16,441
 $41,012
 $8,007
 $49,019
Liabilities: 
  
  
  
  
  
Electric derivative instruments$27,942
 $5,399
 $33,341
 $24,124
 $3,160
 $27,284
Natural gas derivative instruments15,143
 242
 15,385
 28,660
 1,812
 30,472
Total liabilities$43,085
 $5,641
 $48,726
 $52,784
 $4,972
 $57,756




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)2019 2018
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period$(2,446) $2,398
 $(48) $2,009
 $3,949
 $5,958
Changes during period:           
Realized and unrealized energy derivatives:           
Included in earnings1
(4,611) —
 (4,611) 67
 —
 67
Included in regulatory assets / liabilities—
 206
 206
 —
 930
 930
Settlements2,529
 (1,167) 1,362
 (945) (2,217) (3,162)
Transferred into Level 3—
 —
 —
 (150) —
 (150)
Transferred out of Level 3—
 —
 —
 396
 514
 910
Balance at end of period$(4,528) $1,437
 $(3,091) $1,377
 $3,176
 $4,553


Puget Energy and
Puget Sound Energy
Nine Months Ended
September 30,		Puget Energy and
Puget Sound Energy		Three Months Ended
March 31,
(Dollars in Thousands)2019 2018(Dollars in Thousands)20202019
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas TotalLevel 3 Roll-Forward Net Asset/(Liability)ElectricNatural GasTotalElectricNatural GasTotal
Balance at beginning of period$1,362
 $1,673
 $3,035
 $1,098
 $1,923
 $3,021
Balance at beginning of period$(3,379) $1,282  $(2,097) $1,362  $1,673  $3,035  
Changes during period:           Changes during period:
Realized and unrealized energy derivatives:           Realized and unrealized energy derivatives:
Included in earnings2
1,524
 —
 1,524
 2,052
 —
 2,052
Included in earnings1
Included in earnings1
(24,552) —  (24,552) 12,325  —  12,325  
Included in regulatory assets / liabilities—
 2,485
 2,485
 —
 6,260
 6,260
Included in regulatory assets / liabilities—  323  323  —  1,897  1,897  
Settlements(10,380) (3,885) (14,265) (1,599) (5,819) (7,418)Settlements1,626  (513) 1,113  (13,483) (1,100) (14,583) 
Transferred into Level 34,390
 (400) 3,990
 (1,987) —
 (1,987)Transferred into Level 3—  —  —  4,391  (398) 3,993  
Transferred out of Level 3(1,424) 1,564
 140
 1,813
 812
 2,625
Transferred out of Level 3—  —  —  417  686  1,103  
Balance at end of period$(4,528) $1,437
 $(3,091) $1,377
 $3,176
 $4,553
Balance at end of period$(26,305) $1,092  $(25,213) $5,012  $2,758  $7,770  
_______________
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 $(4.5) million and $(0.1) million for the three months ended September 30, 2019 and 2018, respectively.
2.
Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(4.4) million and $1.4 million for the nine months ended September 30, 2019 and 2018, respectively.

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 and $3.1 million for three months ended March 31, 2020 and 2019, respectively.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
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.
26

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2019:March 31, 2020:
Puget Energy and
Puget Sound Energy		Fair Value Range  Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$871
 $5,399
 Discounted cash flow Power prices (per MWh) $6.35
 $40.04
 $31.32
Electric$503  $26,809  Discounted cash flowPower prices (per MWh)$6.00  $38.45  $29.59  
Natural gas$1,679
 $242
 Discounted cash flow Natural gas prices (per MMBtu) $1.84
 $2.48
 $2.11
Natural gas$1,275  $183  Discounted cash flowNatural gas prices (per MMBtu)$1.34  $2.78  $1.85  
_______________
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, 2018:2019:
Puget Energy and
Puget Sound Energy		Fair ValueRange
(Dollars in Thousands)
Assets1
Liabilities1
Valuation TechniqueUnobservable InputLowHighWeighted Average
Electric$651  $4,030  Discounted cash flowPower prices (per MWh)$9.00  $43.85  $33.99  
Natural gas$1,523  $241  Discounted cash flowNatural gas prices (per MMBtu)$1.25  $3.18  $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$4,522
 $3,160
 Discounted cash flow Power prices (per MWh) $11.35
 $66.45
 $29.63
Natural gas$3,485
 $1,812
 Discounted cash flow Natural gas prices (per MMBtu) $1.84
 $5.80
 $3.18
___________
____________
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. As of September 30, 2019March 31, 2020, and December 31, 2018,2019, a hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.9$5.1 million and $2.6$2.5 million, respectively.


Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.
As of September 30, 2019,March 31, 2020, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and found no impairment. liabilities were revalued in accordance with ASC 805, "Business Combinations". Differences between the fair market value and the carrying value of assets held as PSE were recorded at PE. The Rocky Reach contract was determined to be impaired due to a decrease in forward prices for this contract of 7.6% from December 31, 2019, causing an impairment of $52.6 million. While this impairment of the intangible asset held at PE is the result of a decline in forward prices and the corresponding valuation impact, the underlying power purchase contract is included within rates at PSE.
27

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

Puget Energy
(Dollars in Thousands)
Valuation DateContract Name  Carrying ValueFair ValueWrite Down
March 31, 2020Rocky Reach  $147,168  $94,603  $52,565  


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

The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase
contracts' fair value:
(6)Retirement Benefits


Puget Energy
Valuation DateUnobservable Input  LowHighAverage
March 31, 2020Power prices (per MWh) $10.23  $29.05  $20.88  
Power contract costs per quarter (in thousands) 6,308  7,085  6,468  
December 31, 2019Power prices (per MWh) $11.75  $31.44  $22.53  
Power contract costs per quarter (in thousands) $6,237  $7,087  $6,421  



(6) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  Starting with January 1, 2014, all the United Association of Plumbers and Pipefitters (UA) represented employees will receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014, for employees represented by the International Brotherhood of Electrical Workers Union (IBEW), participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also maintainshas a non-qualified supplemental executive retirement planSupplemental Executive Retirement Plan (SERP) for certain key senior management employees. Officers hired after Januaryemployees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, participate insuch that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an Officer Restoration Benefit as part ofaccount with the Deferred Compensation Plan for Key Employees. Plan.
In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries.
Puget Energy's retirement plans were re-measuredremeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans.

In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other
28

components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.
The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2020 and nine months ended September 30, 2019 and 2018:2019:
Puget EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended March 31,
(Dollars in Thousands)202020192020201920202019
Components of net periodic benefit cost:
Service cost$5,997  $5,287  $228  $256  $49  $16  
Interest cost6,298  7,216  378  578  91  112  
Expected return on plan assets(12,502) (12,624) —  —  (97) (97) 
Amortization of prior service cost(495) (495) 87  83  —  —  
Amortization of net loss (gain)1,981  251  586  341  (22) (63) 
Net periodic benefit cost$1,279  $(365) $1,279  $1,258  $21  $(32) 

Puget Sound EnergyQualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months Ended March 31,
(Dollars in Thousands)202020192020201920202019
Components of net periodic benefit cost:
Service cost$5,997  $5,287  $228  $256  $49  $16  
Interest cost6,298  7,216  378  578  91  112  
Expected return on plan assets(12,504) (12,628) —  —  (97) (98) 
Amortization of prior service cost(393) (393) 87  83  —  —  
Amortization of net loss (gain)4,656  3,165  659  433  (36) (109) 
Net periodic benefit cost$4,054  $2,647  $1,352  $1,350  $7  $(79) 

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Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
 Three Months Ended September 30,
(Dollars in Thousands)2019 2018 2019 2018 2019 2018
Components of net periodic benefit cost:           
Service cost$6,418
 $6,218
 $256
 $212
 $13
 $17
Interest cost7,252
 6,917
 578
 530
 84
 113
Expected return on plan assets(12,439) (12,533) —
 —
 (100) (119)
Amortization of prior service cost(495) (495) 83
 11
 —
 —
Amortization of net loss (gain)362
 716
 341
 394
 (156) (80)
Net periodic benefit cost$1,098
 $823
 $1,258
 $1,147
 $(159) $(69)


Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
 Nine Months Ended September 30,
(Dollars in Thousands)2019 2018 2019 2018 2019 2018
Components of net periodic benefit cost:           
Service cost$16,992
 $17,068
 $768
 $635
 $46
 $52
Interest cost21,685
 20,477
 1,735
 1,590
 308
 333
Expected return on plan assets(37,686) (37,652) —
 —
 (295) (354)
Amortization of prior service cost(1,485) (1,485) 249
 33
 —
 —
Amortization of net loss (gain)863
 1,640
 1,024
 1,185
 (281) (252)
Net periodic benefit cost$369
 $48
 $3,776
 $3,443
 $(222) $(221)

 Puget Sound Energy
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
 
  Three Months Ended September 30,
 (Dollars in Thousands)2019 2018 2019 2018 2019 2018
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$6,418
 $6,218
 $256
 $212
 $13
 $17
 Interest cost7,252
 6,917
 578
 530
 84
 113
 Expected return on plan assets(12,443) (12,542) —
 —
 (100) (119)
 Amortization of prior service cost(393) (393) 83
 11
 —
 —
 Amortization of net loss (gain)3,328
 3,928
 433
 517
 (202) (134)
 Net periodic benefit cost$4,162
 $4,128
 $1,350
 $1,270
 $(205) $(123)


 Puget Sound Energy
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
 
  Nine Months Ended September 30,
 (Dollars in Thousands)2019 2018 2019 2018 2019 2018
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$16,992
 $17,068
 $768
 $635
 $46
 $52
 Interest cost21,685
 20,477
 1,735
 1,590
 308
 333
 Expected return on plan assets(37,700) (37,680) —
 —
 (295) (354)
 Amortization of prior service cost(1,180) (1,180) 250
 33
 —
 —
 Amortization of net loss (gain)9,657
 11,188
 1,300
 1,552
 (421) (417)
 Net periodic benefit cost$9,454
 $9,873
 $4,053
 $3,810
 $(362) $(386)

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2019March 31, 2020 and December 31, 2018:2019:
Puget Energy and
Puget Sound Energy		Qualified
Pension Benefits		SERP
Pension Benefits		Other
Benefits
Three Months EndedYear EndedThree Months EndedYear EndedThree Months EndedYear Ended
(Dollars in Thousands)March 31,
2020		December 31,
2019		March 31,
2020		December 31,
2019		March 31,
2020		December 31,
2019
Change in benefit obligation:
Benefit obligation at beginning of period$774,305  $677,643  $63,000  $55,708  $11,627  $10,636  
Amendments—  —  —  —  —  9,049  
Service cost5,997  22,656  228  1,023  49  61  
Interest cost6,298  28,913  378  2,314  91  410  
Curtailment Loss / (Gain)—  —  —  —  —  (7,486) 
Actuarial loss (gain)—  84,272  (478) 6,756  —  (287) 
Benefits paid(11,250) (36,740) (13,649) (2,801) (251) (982) 
Medicare part D subsidy received—  —  —  —  —  226  
Administrative Expense—  (2,439) —  —  —  —  
Benefit obligation at end of period$775,350  $774,305  $49,479  $63,000  $11,516  $11,627  
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,
2019		 December 31,
2018		 September 30,
2019		 December 31,
2018		 September 30,
2019		 December 31,
2018
Change in benefit obligation:           
Benefit obligation at beginning of period$677,643
 $700,481
 $55,708
 $55,754
 $10,636
 $11,454
Amendments—
 —
 —
 1,446
 —
 —
Service cost16,992
 22,757
 768
 847
 46
 69
Interest cost21,685
 27,303
 1,735
 2,120
 308
 444
Actuarial loss (gain)1,644
 (29,067) —
 1,122
 (909) (379)
Benefits paid(33,619) (42,662) (2,297) (5,581) (719) (1,037)
Medicare part D subsidy received—
 —
 —
 —
 226
 85
Administrative Expense—
 (1,169) —
 —
 —
 —
Benefit obligation at end of period$684,345
 $677,643
 $55,914
 $55,708
 $9,588
 $10,636


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, 20192020, are expected to be at least $18.0 million, $6.2$26.1 million and $0.3 million, respectively. During the three months ended September 30,March 31, 2020, the Company contributed $13.6 million to fund the SERP. During the three months ended March 31, 2019, the Company contributed $18.0 million and $1.3$0.5 million to fund the qualified pension plan and SERP, respectively. During the nine months ended September 30, 2019, the Company contributed $18.0 million and $2.3 million to fund the qualified pension plan and SERP, respectively.SERP. The Company contributed an immaterial amount to fund the other postretirement plans.




(7) Regulation and Rates


General Rate Case
PSE filed a general rate case (GRC) with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company includedcompleted an attrition adjustment mechanism tostudy and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC,testimony, which provided certain updates as discussed in ourto the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

On March 17, 2020, PSE filed with the Commission a Motion to Extend the Suspension Date (Motion). In its Motion, PSE requested and agreed to waive the statutory deadline associated with the GRC Dockets for up to 60 days, from May 20, 2020, to July 20, 2020. PSE explained in its Motion that, in recent weeks, COVID-19 has caused an unprecedented global health crisis impacting nearly all aspects of society, and that residents and businesses in the Company’s service territory have been severely
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impacted. PSE believes extending the suspension date in this proceeding would help mitigate the effects of any rate increases on customers, and would benefit the Commission to the extent there are any disruptions or delays to Commission operations as a result of the virus or its operational response thereto. On March 17, 2020, the Commission granted PSE's Motion and extended the suspension date until July 20, 2020.

Expedited Rate Filing
On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.
On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million annualrate increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.
The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric.electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019:
1)excess deferred taxes for non-plant- related book/tax differences for periods prior to March 1, 2019,
2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and
3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.
1)excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019,
2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and
3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.
The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in the test year of the filing. The settlement agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s next2019 GRC. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which beganends May 1, 2019.2020.


Washington Commission Tax Deferral Filing
The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform.  The requested deferral accounting treatment resultsresulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas and became effective May 1, 2018, by operation of law.
The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018, (the time period that encompasses

the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.
As a result of the Washington Commission’sCommission's final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2018, through February 28, 2019, was addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collectionover-
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collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owned to customers will be greater than $0.1 million, PSE will submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021.


Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.
On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.
On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.
On September 30, 2019,March 31, 2020, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that all of electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 20192020 decoupling revenue.


Electric RegulationPower 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 Rateshydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:

Company’s 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  

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In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The deferral period requested was January 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC.  In November 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.
For the three months ended March 31, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $25.1 million of which $4.0 million was apportioned to customers and $0.5 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $43.1 million for the three months ended March 31, 2019, of which $14.3 million was apportioned to customers and accrued 0 interest on the total deferred customer balance. Power costs were higher than the allowed baseline in the first quarter of 2020 which led to an increase in the PCA deferral, although it was a lower under-collection compared to the same period in 2019, which also saw actual power costs that were higher than the baseline but by a larger margin, resulting in a higher under-collection. The higher under-collection in 2019 was the result of high power prices in the first quarter of 2019 which were due to cold weather in February and early March of 2019, which drove regional loads and demand for power up, and Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices.

Purchased Gas Adjustment
On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be from May 2019 through April 2020. Following the recovery period, any remaining balances of the out-of-cycle PGA supplemental filing will be rolled into regular annual PGA filing effective November 1, 2020.
On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.
As of December 31, 2018, PSE had a beginning PGA receivable balance of $9.9 million. For the three months ended March 31, 2019, PSE incurred actual natural gas costs of $224.7 million, of which $98.1 million was recovered through rates. The difference between actual and allowed costs, less interest $0.6 million, resulted in a PGA receivable of $137.1 million. As of December 31, 2019, PSE had a beginning PGA receivable balance of $132.8 million. For three months ended March 31, 2020, PSE incurred actual natural gas costs of $114.4 million, of which $157.2 million was recovered through rates. The difference between actual and allowed costs, plus interest of $1.4 million, resulted in a PGA receivable of $91.3 million.

Get to Zero Depreciation Deferral
On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. As of March 31, 2020 and December 31, 2019, PSE had deferred GTZ depreciation expense balances of $31.3 million and $21.7 million, respectively. In addition to the depreciation expense deferral, PSE requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. As of March 31, 2020 and December 31, 2019, PSE has a deferred carrying charge balance of $1.2 million and $0.5 million, respectively. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and is currently being reviewed by the Washington Commission.
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Crisis Affected Customer Assistance Program
On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60.The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers.CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low income programs.The program will automatically end when all of the funds are disbursed.Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020.

Storm Damage Deferral Accounting
The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the ninethree months ended September 30, 2019,March 31, 2020, PSE incurred $39.3$9.9 million in storm-related electric transmission and distribution system restoration costs, of which the Company0 amount was deferred $28.5 million and $0.4 million as a regulatory assets related to storms that occurred in 2019 and 2018, respectively.asset. This compares to $8.9$38.4 million incurred in storm-related electric transmission and distribution system restoration costs for the ninethree months ended September 30, 2018,March 31, 2019, of which no amount wasthe Company deferred $1.1 million and $26.4 million as regulatory assets related to a regulatory asset.storms that occurred in 2018 and 2019, respectively. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.



(8) Commitments and Contingencies


Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two2 oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.
OnConsistent with a June 11, 2019 announcement, Talen made a public announcement that Colstrippermanently shut down Units 1 and 2 will be shut down at the end of the year due to operational losses associated with the Units. The regulatory asset associated with early retirement of Colstrip Units 1 and 2 increased from $130.7 million as ofwere retired effective December 31, 2018, to $178.2 million as of September 30, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under the agreement with NorthWestern Energy, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2019, and determined that these criteria were not met. As such, Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2019.
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Other Commitments and Contingencies
There have been no material changesIn addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, during the three months ended March 31, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $473.7 million through 2037.
For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2018.2019.


Coronavirus Pandemic
The outbreak of the novel coronavirus (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The full impact on the Company's business from the pandemic, including governmental and regulatory response actions, is unknown at this time and difficult to predict. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions.
At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to 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 likelihood of an impact to the Company, and the severity of any impact that does occur, could increase the longer the global pandemic persists.


(9)  Leases


PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNGTacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 26 years, some of which50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option.
During the leasesfourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for up toan additional 25 years.years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of
$14.7 million.
The components of lease expensecost were as follows:

Puget Energy and
Puget Sound Energy		Three Months Ended September 30, Nine Months Ended
September 30,		Puget Energy and
Puget Sound Energy		Three Months Ended
March 31,
(Dollars in Thousands)2019 2019(Dollars in Thousands)20202019
Finance lease cost:   Finance lease cost:
Amortization of right-of-use asset$128
 $410
Amortization of right-of-use asset$152  $158  
Interest on lease liabilities10
 29
Interest on lease liabilities10  9  
Total finance lease cost$138
 $439
Total finance lease cost$162  $167  
   
Operating lease cost1
$5,311
 $15,318
Operating lease cost1
$5,480  $4,784  
_______________
1
Includes $0.3 million and $0.8 million allocated to PLNG at PE related to the Tacoma land lease at three and nine months ended September 30, 2019, respectively.

1 Includes $0.3 million allocated to PLNG at PE related to the Port of Tacoma lease for each of the three months ended March 31, 2020 and 2019, respectively.
35


Supplemental cash flow information related to leases was as follows:
Puget Energy and
Puget Sound Energy		Three Months Ended September 30, Nine Months Ended
September 30,		Puget Energy and
Puget Sound Energy		Three Months Ended
March 31,
(Dollars in Thousands)2019 2019(Dollars in Thousands)20202019
Cash paid for amounts included in the measurement of lease liabilities:   Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases$(3,678) $(10,437)
Operating cash flow for operating leasesOperating cash flow for operating leases$3,773  $4,346  
Investing cash flow for operating leases1
(1,633) (4,881)
Investing cash flow for operating leases1
1,707  438  
Operating cash flow for finance leases(10) (29)Operating cash flow for finance leases10  9  
Financing cash flows for finances leases(129) (410)
Financing cash flow for finance leasesFinancing cash flow for finance leases152  158  
_______________
1
Includes $0.3 million and $0.8 million allocated to PLNG at PE related to the Tacoma land lease at three and nine months ended September 30, 2019, respectively.

1 Includes $0.3 million allocated to PLNG at PE related to the Port of Tacoma lease for each of the three months ended March 31, 2020 and 2019, respectively.

Supplemental balance sheet information related to leases was as follows:
Puget Sound Energy
(Dollars in Thousands)March 31,December 31,
Operating Leases20202019
Operating lease right-of-use asset$180,188  $183,048  
Operating leases liabilities current16,183  15,862  
Operating lease liabilities long-term170,638  174,327  
Total Operating lease liabilities:$186,821  $190,189  
Finance Leases
Common Plant$1,337  $1,488  
Other current liabilities657  669  
Other deferred credits656  811  
Total finance lease liabilities$1,313  $1,480  
Weighted Average Remaining Lease Term
Operating leases19.12 Years19.24 Years
Finance leases2.48 Years2.76 Years
Weighted Average Discount Rate
Operating leases3.59 %3.59 %
Finance leases2.98 %2.98 %


36
Puget Sound Energy 
(Dollars in Thousands)At September 30,
Operating Leases2019
Operating lease right-of-use asset$168,491
 

Operating leases liabilities current$(15,173)
Operating lease liabilities long-term(159,913)
Total Operating lease liabilities:$(175,086)
 

Finance Leases

Common Plant$1,268
 

Other current liabilities$(585)
Other deferred credits(682)
Total finance lease liabilities$(1,267)
  
Weighted Average Remaining Lease Term 
Operating leases13.15 years
Finance leases2.96 years
  
Weighted Average Discount Rate 
Operating leases3.77%
Finance leases2.98%
  
Supplemental Non-cash Information on Lease Liabilities Arising from Obtaining New Right-of-Use Assets 
Operating leases$2,032
Finance leases$373


The following tables summarize the Company’s estimated future minimum lease payments as of September 30, 2019,March 31, 2020, and December 31, 2018,2019, respectively:

Maturities of lease liabilities
Future Minimum Lease Payments

Maturities of lease liabilitiesFuture Minimum Lease Payments
(Dollars in Thousands)(Dollars in Thousands)
At September 30,Operating Leases Finance Leases
2019 (remaining three months)$4,968
 $133
202021,514
 554
At March 31,At March 31,Operating LeasesFinance Leases
2020 (remaining nine months)2020 (remaining nine months)$15,649  $481  
202121,791
 416
202122,762  508  
202221,375
 184
202222,095  279  
202320,935
 25
202321,657  98  
2024202420,932  —  
Thereafter135,492
 —
Thereafter160,676  —  
Total lease payments226,075
 1,312
Total lease payments$263,771  $1,366  
Less imputed interest(50,989) (45)Less imputed interest(76,950) (53) 
Total$175,086
 $1,267
Total$186,821  $1,313  


Maturities of lease liabilitiesFuture Minimum Lease
Payments
(Dollars in Thousands)
At December 31,Operating LeasesFinance Leases
2020$22,500  $643  
202122,527  508  
202221,856  279  
202321,415  98  
202420,690  —  
Thereafter160,410  —  
Total lease payments$269,398  $1,528  
Less imputed interest(79,209) (48) 
Total net present value$190,189  $1,480  
Maturities of lease liabilitiesFuture Minimum Lease Payments
(Dollars in Thousands)
At December 31,Operating Leases Finance Leases
2019$20,635
 $495
202020,704
 446
202120,630
 311
202220,202
 82
202319,223
 —
Thereafter132,889
 —
Total minimum lease payments$234,283
 $1,334



(10) Other


Long-Term Debt
In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans underThe Company had no new long-term debt activities in the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.
On August 30, 2019, PSE issued $450.0 million of senior notes at an interest rate of 3.25%.  The notes pay interest semi-annually and are due to mature on September 15, 2049. Proceeds from the sale of the notes were used to repay outstanding short- term debt under the Company’s commercial paper program.
On September 26, 2019, Puget Energy entered into a separate $210.0 million, 3 years term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program.
three months ended March 31, 2020. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2018.2019.



Short-Term Debt

During the three months ended March 31, 2020, commercial paper markets were significantly impacted for a period of time due to COVID-19, during which time the Company drew short term funding from its credit facility. As of March 31, 2020, $60.0 million was drawn under PSE's credit facility and $16.0 million was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2019.
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Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations


The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2018.2019. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.operations, including the COVID-19 pandemic.


Overview


Puget Energy is an energy services holding company and substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation (BCIMC), the Alberta Investment Management Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCIMC was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17th, 2019. Puget Energy and PSE are collectively referred to herein as “the Company.”
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.

COVID-19 Update
A novel strain of coronavirus (COVID-19) was first identified in December 2019, and subsequently declared a pandemic by the World Health Organization. To date, COVID-19 has surfaced in nearly all regions around the world and resulted in travel restrictions and business slowdowns or shutdowns in affected areas. On January 21, 2020, authorities confirmed the first COVID-19 case in Washington State, followed by the first confirmed virus-related death in Washington State on February 29, 2020, in each case, in the Company’s service territory.
In response to the outbreak and business disruption, first and foremost, we have prioritized the health and safety of our customers, employees, and the communities in our service territory implementing a number of changes including not disconnecting customers for non-payment, receiving Commission approval to waive late fees, and filing a motion with the Commission to waive the statutory deadline for the Company’s General Rate Case for up to 60 days, from May 20, 2020, until July 20, 2020, establishing a Crisis-Affected Customer Assistance Program (CACAP), implementing social distancing measures for our employees and using remote workforce where possible. PSE continues to serve our customers and has
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implemented business continuity and emergency response plans to continue to provide electricity and natural gas services to customers and otherwise support the Company’s operations.
We are continuing to monitor developments involving our workforce, customers, electricity and natural gas demand, commodity costs and suppliers but cannot predict the impact of COVID-19 on our results of operations, financial condition and ongoing operations. An extended slowdown of the United States' economic growth, demand for commodities and/or material changes in governmental policy could result in lower economic growth and lower demand for electricity and natural gas in our service territory. Moreover, such extended slowdown will affect the ability of various customers, contractors, suppliers and other business partners to fulfill their obligations, which could have a material adverse effect on our results of operations, financial condition and ongoing operations.
The Company anticipates, depending on the length and severity of the pandemic crisis (including, but not limited to, continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and any resurgence of the COVID-19 virus) that electric and gas loads will likely be impacted in the remainder of 2020 at a minimum. Residential load, which comprises a significant portion of the Company's total retail revenues at 59.0%, would be expected to increase due to work from home requirements, and Commercial load, which represents 35.9% of the Company's total retail revenues, would be expected to decrease as a result of the restrictions and shutdowns to commercial business activities. Any such revenue reductions would be offset by reduced electric and gas supply costs and the effects of decoupling. Industrial customers, who represent only 4.4% 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. To the extent that the Company incurs material, unexpected expenses associated with the pandemic, such as increased uncollectible accounts receivable, the Company would explore regulatory accounting policies and rate recovery mechanisms to address any negative impacts to financial results.
On March 27, 2020, the U.S. Government enacted the CARES Act, which provides approximately $2 trillion of economic relief and stimulus to support the national economy during the COVID-19 epidemic. This package included support for individuals, large corporations, small business, and health care entities, among other affected groups. The utility industry, including the Company, were not direct beneficiaries of the stimulus, however, the Company continues to review the provisions of the CARES Act and assess the potential impact on the Company’s operations.
Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended September 30, 2019March 31, 2020, 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 2019 and will continue to do so in future years.  Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process.  The principal business, economic and other factors that affect PSE'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 (ROR);
•Availability and access to capital and the cost of capital;
•Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
•Wholesale commodity prices of electricity and natural gas;
•Increasing capital expenditures with additional depreciation and amortization;
•Failure to complete capital projects on schedule and within budget or the abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;
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•Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base and customer rates;
•General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; 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;
•The effectiveness of PSE’s risk management policies and procedures;
•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;
•Acts of war or terrorism;
•Risks due to pandemics, including supply shortages, rising costs, disruption to vendor or customer relationships, the potential for reputational harm, the impact of government, business and company closure of facilities, customer or contract defaults; concerns of safety to employees and customers, potential costs due to quarantining of employees and work-from-home policies.

Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 20192020 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly, under existing modified historical ratemaking,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 after the investment is made.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 an expense ora capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.
Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. Although not specified by Washington state law, theThe Washington Commission also sets natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.


General Rate Case Filing
PSE filed a general rate case (GRC) with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company includedcompleted an attrition adjustment mechanismstudy and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC,testimony, which provided certain updates as discussed in ourto the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

On March 17, 2020, PSE filed with the Commission a Motion to Extend the Suspension Date. In its Motion, PSE requested and agreed to waive the statutory deadline associated with the GRC Dockets for up to 60 days, from May 20, 2020, to July 20, 2020. PSE explained in its Motion that, in recent weeks, COVID-19 has caused an unprecedented global health crisis

40

impacting nearly all aspects of society, and that residents and businesses in the Company’s service territory have been severely impacted. PSE believes extending the suspension date in this proceeding would help mitigate the effects of any rate increases on customers, and would benefit the Commission to the extent there are any disruptions or delays to Commission operations as a result of the virus or its operational response thereto. On March 17, 2020, the Commission granted PSE's Motion to Extend the Suspension Date until July 20, 2020.
For further details regarding the 2019 GRC filing, see Note 7, "Regulations and Rates" to the consolidated financial statements included in part 1 of this report.

Expedited Rate Filing
On November 7, 2018, PSE filed an ERF with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Washington Commission approved the settlement with one condition:condition. The settlement requires that PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

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

Washington Commission Tax Deferral Filing
The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform.  The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%. Other outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.
The Washington Commission approved the following PSE requests to change rates to reflect the new corporate tax rates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
Electric:
May 1, 2018(3.4)%$(72.9)
Natural Gas:
May 1, 2018(2.7)%$(23.6)
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
Electric:   
May 1, 2018(3.4)% $(72.9)
Natural Gas:   
May 1, 2018(2.7) (23.6)


Decoupling Filings
On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate cap, which limits the amount of previously deferred revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism is to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.
On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.
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On September 30, 2019,March 31, 2020, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding regulatory asset balance.  Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that all of electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 20192020 decoupling revenue.

The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Effective DateAverage
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Electric:   Electric:
May 1, 2020May 1, 20200.2%$2.0
May 1, 20190.9% $20.6May 1, 20190.920.6
May 1, 2018(1.1) (25.2)May 1, 2018(1.1)(25.2)
Natural Gas: Natural Gas:
May 1, 2020May 1, 2020(0.5)%$(4.8)
May 1, 2019(5.3)% $(45.9)May 1, 2019(5.3)(45.9)
May 1, 20181.7 15.9May 1, 20181.715.9
_______________
1
There were no excess earnings for either electric or natural for the rates effective May 1, 2019. The increase in revenue is net of reductions from excess earnings of $10.0 million for electric and $4.9 million for natural gas effective May 1, 2018.

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

Electric Rates
Power Cost Adjustment Mechanism
PSE currently has a power cost adjustment (PCA) mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions.  Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.
Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:
Company's 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


In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The deferral period requested was January 1, 2017, through December 31, 2017, when rates wentwere to go into effect from PSE's 2017 GRC.  In November 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.
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For the ninethree months ended September 30, 2019,March 31, 2020, in its PCA mechanism, PSE under-recoveredunder recovered its powerallowable costs by $48.9$25.1 million of which $19.5$4.0 million amount was apportioned to customers.customers and $0.5 million of interest was accrued on the deferred customer balance. This compares to an under-recoveryunder recovery of powerallowable costs of $7.7$43.1 million for the ninethree months ended September 30, 2018March 31, 2019, of which no amounts were$14.3 million was apportioned to customers.customers and accrued no interest on the total deferred customer balance. Power costs have beenwere higher than the allowed base linebaseline in 2019the first quarter of 2020 which has led to an increase in the PCA deferral causing analthough it was a lower under-collection compared to the prior year. Actualsame period in 2019, which also saw actual power costs that were lesshigher than the baseline ratesbut by a larger margin, resulting in 2018 which caused an over-collection. Load increased 4.2% year over year which is one drivera higher under-collection. The higher under-collection in 2019 was the result of increased power cost. This was driven by colder temperatures in February and early March. Additionally,high power prices increased duringin the period as comparedfirst quarter of 2019 due to the prior year. Increase in prices are due to: (i) Coldcold weather in February and early March of 2019, which drove regional loads up; (ii)and demand for power up, and Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a transmission line contributed to a liquidity crisis at Mid-C, resulting in high market power prices; and (iv)) The relative prices of natural gas and power reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.



Power Cost Adjustment Clause Filing
On July 1, 2019, PSE updated its rates under Schedule 95 itsrates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments.
The following table sets forth the rate changepower 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)
July 1, 20191
(1.2)%$(24.9)
May 1, 20190.13.3
_______________
1.The rates will be zeroed out following the July 2019 through June 2020 period. The actual residual amount resulting at July 31, 2020 will be included in the electric Schedule 129 Low Income Program rates that become effective October 1, 2020.


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Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
July 1, 2019(1.2)% $(24.9)


Electric Conservation Rider
The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 20200.9%$17.8
May 1, 2019(0.9)(17.5)
May 1, 2018(0.8)(18.0)
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 2019(0.9)% $(17.5)
May 1, 2018(0.8) (18.0)


Electric Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 20200.07%$1.4
May 1, 2019(0.2)(5.1)
May 1, 2018(0.1)(1.3)
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2019(0.2)% $(5.1)
May 1, 2018(0.1) (1.3)


Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federalfederal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1. Additionally, this tracker is impacted by the TCJA previously discussed. Accordingly, PSE filed for a one-time rate change to be effective May 1, 2018, to recognize the decrease in the federal corporate income tax rate from 35% to 21%.

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

Effective DateAverage
Percentage
Increase (Decrease)
in Rates from prior year		Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2020(0.04)%$(37.8)
January 1, 20190.1(38.7)

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Effective Date
Average
Percentage
Increase (Decrease)
in Rates from prior year
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2020 - proposed—% $(37.8)
January 1, 20190.1 (38.7)
May 1, 20180.4 (40.1)
January 1, 20180.2 (48.2)


Residential Exchange Benefit
The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration.Administration (BPA).  Rates change biennially on October 1.
The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Total credit to be passed back to eligible customers
(Dollars in Millions)
October 12, 20190.01%$(81.8)
October 1, 2017(0.6)(80.8)
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
October 12, 2019—% $(81.8)
October 1, 2017(0.6) (80.8)


Natural Gas Rates
Natural Gas Conservation Rider
The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 20200.4%$3.5
May 1, 20190.11.1
 Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
 
 
 
 May 1, 20190.1% $1.1


Natural Gas Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and adjustments to the ratetrue-up from the prior year.

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

Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
Effective DateAverage Percentage Increase (Decrease) in RatesIncrease (Decrease) in Revenue (Dollars in Millions)
May 1, 2020May 1, 2020(0.3)%$(2.8)
May 1, 2019(0.2)% $(1.6)May 1, 2019(0.2)(1.6)
May 1, 2018(0.2) (2.2)May 1, 2018(0.2)(2.2)



Natural Gas Cost Recovery Mechanism
The purpose of the cost recovery mechanism (CRM) is to recover capital costs related to projects included in PSE's pipepipeline replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.
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The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20190.8%$7.0
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 Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1st1, although out-of-cycle rate changes are allowed at other times of the year if needed.
On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be from May 2019 through April 2020. Following the recovery period, any remaining balances of the out-of-cycle PGA supplemental filing will be rolled into regular annual PGA filing effective November 1, 2020.
On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE have requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition ofto continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two yearsyear period, instead of the historic one year period, from November 2019 through October 2021.

As of December 31, 2018, PSE had a beginning PGA receivable balance of $9.9 million. For the three months ended March 31, 2019, PSE incurred actual natural gas costs of $224.7 million, of which $98.1 million was recovered through rates. The difference between actual and allowed costs, less interest $0.6 million, resulted in a PGA receivable of $137.1 million. As of December 31, 2019, PSE had a beginning PGA receivable balance of $132.8 million. For three months ended March 31, 2020, PSE incurred actual natural gas costs of $114.4 million, of which $157.2 million was recovered through rates. The difference between actual and allowed costs, plus interest of $1.4 million, resulted in a PGA receivable of $91.3 million.
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, 201913.4%$118.3
May 1, 20196.354.0
November 1, 2018(10.9)(98.4)


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Other Proceedings
Microsoft Special Contract
Following discussions between PSE, the Microsoft Corporation, and others, and after completing a negotiated regulatory process, in July 2017, the Washington Commission issued an order in July 2017 approving a special contract between PSE and Microsoft relating to retail access for Microsoft loads currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to Microsoft must be carbon free, (iii) there will be no reduction in Microsoft's funding of PSE’s conservation programs, (iv) Microsoft paid a transition fee that was a straight pass-through to customers and (v) Microsoft will fund enhanced low-income support. Microsoft began taking service under the special contract on April 1, 2019, after meeting the eligibility requirements under the special contract.


Voluntary Long-Term Renewable Energy
Effective September 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product. This provides customers with electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially 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 that will be constructedcurrently under construction in the region by a developer under contract to PSE to meet the demand for this voluntary renewable energy product.PSE. The project is fully subscribed and is expected to begin generating power in early 2020. Twenty-one customers will receive the anticipated output of the project.
In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase 2 offering will be a blend of the phase 1 wind and a solar project. In October 2018, the Washington Commission approved an expansion of the solar project from 120 MW to 150 MW.be built in Washington. Phase 1 customers will receive wind through 2020;2020 and then willare expected to receive the blended energy in March 2021. Open enrollment for phase 2, which is fully subscribed, began on August 31, 2018. TwentyAn additional twenty customers will start receiving energy through phase 2 of the program inby March 2021.


Crisis Affected Customer Assistance Program
On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60.The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers.CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is fully compatible with other low-income programs.The program will automatically end when all of the funds are disbursed.Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020.

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


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



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
47

and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
Compliance with these or other future regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.


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


Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the three months ended March 31, 2019, and 2020.

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



48

Electric Margin
Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory.
The following chart displays the details of PSE's electric margin changes for the three months ended September 30, 2018March 31, 2019 and 2019:2020:
chart-c0a9306ceae056bf862.jpgpsd-20200331_g3.jpg
______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.


Three months ended September 30, 2018Months Ended March 31, 2019 compared to 20192020
Electric Operating Revenue
Electric operating revenues decreased $20.6$129.8 million from the prior year primarily due to a decrease in other revenues of $86.4 million, a decrease in electric retail sales of $19.0$36.1 million, a decrease in sales to other revenuesutilities of $8.4$10.0 million, and a decrease in other decoupling revenue of $3.3 million;$6.9 million partially offset by an increase in sales to other utilities of $6.7 million and an increase in decoupling revenue of $3.3$9.5 million. These items are discussed in detail below.
•Electric retail sales decreased $19.0$36.1 million due to a decrease in rates of $11.9 million and a decrease of $7.1$26.8 million from reduced retail electricity usage, or 4.3%, and a decrease in rates of 1.6%$9.3 million compared to the prior year. The reduction in usage was due to a decrease of industrial, commercial industrial and residential use per customer usage of 2.4%6.0%, 0.9%7.8% and 0.7%1.7%, respectively, which was driven by a decrease in heating degree days of 11.2% and3.5%; partially offset by an increase in retail customers of 1.4% compared to 2018.2019. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.
•Sales to other utilities increased $6.7 decreased $10.0 million due to a 49.3% increase50.0% decrease in volumes soldprice partially offset by a 22.2% decrease in price. Volumes were higher because market conditions made it economic to run gas fired resources to meet regional demand, and PSE’s system load was lower than 2018 load. The decrease in average price was because 2018 prices were abnormally high as a result of higher than normal temperatures.
Decoupling revenue increased $3.3 million, primarily attributable to a $2.7 million increase in PCA fixed cost deferral revenues, driven by decreased usage, as noted above in the retail revenue section. This resulted in allowed PCA revenues

being $1.0 million greater than actual PCA revenues in the current year, whereas actual PCA revenues were $1.7 million greater than allowed PCA revenues in the prior year.
Other decoupling revenue decreased $3.3 million, primarily related to cash refunds of earnings in excess of allowed ROR. In 2018, earnings in excess of allowed ROR of $2.1 million was returned to customers. In the current year, there were no such returns to customers. In addition, current period amortization of prior year over-collection increased by $1.5 million year over year, resulting from higher amortization rates, offset in part by decreased usage.
Transportation and other revenue decreased $8.4 million primarily due to a decrease in production tax credit (PTC) deferral revenue of $8.5 million for the re-purpose of the PTCs, a decrease in non-core gas sales of $2.3 million and a decrease in green energy option revenue of $1.6 million partially offset by an increase in tax reform deferrals returned to customers in 2019 for revenue subject to refunds of $4.9 million.

Electric Power Costs
Electric power costs decreased $18.8 million primarily due to decrease of $41.5 million of purchased electricity costs and was partially offset by an increase of $22.6 million of electric generation fuel expense. These items are discussed in detail below.
Purchased electricity expense decreased $41.5 million primarily due to an 18.1% decrease in wholesale electricity purchases and a 12.0% decrease in wholesale prices. The decrease in purchases was primarily driven by a decrease in load and a decrease in hydro purchases from Mid-Columbia of 16.9%, due to unfavorable hydro conditions, driving an increase in combustion turbine generation, as noted in the section below.
Electric generation fuel expense increased $22.6 million primarily due to a $10.6 million increase in combustion turbine generation costs primarily driven by an increase in generation of 20.0% as a result of favorable heat rates, unfavorable wholesale electricity prices and reduced hydro purchases of 16.9%.

The following chart displays the details of PSE's electric margin changes for the nine months ended September 30, 2018 and 2019:
chart-6588367ea0ac59689c2.jpg
______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Nine months ended September 30, 2018 compared to 2019
Electric Operating Revenue
Electric operating revenues increased $87.8 million primarily due to transportation and other revenues of $99.5 million, sales to other utilities of $23.1 million, decoupling revenue of $6.7 million, and other decoupling revenue of $3.6 million, partially offset by lower electric retail sales of $45.1 million.  These items are discussed in detail below.
Electric retail sales decreased $45.1 million due to a decrease in rates of $52.2 million, offset by an increase of $7.1 million from additional retail residential electricity usage of 1.9% compared to the prior year which was driven by an increase in residential retail customers of 1.4% compared to 2018. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.
Sales to other utilities increased $23.1 million due to a 12.1% increase in price and a 23.7%25.6% increase in sales volume. During the 1stfirst quarter of 2019, wholesale prices increased 115.7% due to spot power prices at Mid-Columbia that increased to an 18-year high largely driven by record-breaking natural gas prices and there wasprices. In addition, an increase in volumes from an additional 111.8% of combustion turbine (CT) generation as a result of favorable heat rates and increased demand for wholesale market power.
power contributed to the strong revenue in the 2019 period.
•Decoupling revenue increased $6.7$9.5 million, the combination of a $1.4$6.4 million decreaseincrease in PCA Fixed Cost Deferral revenues and a $3.1 million increase in delivery deferral revenues, and an $8.1primarily attributable to decreased usage, as noted
49

above in the retail sales section. This resulted in allowed electric revenues being greater than actual electric revenues in the current year, compared to less than actual electric revenues in the prior year.
•Other decoupling revenue decreased $6.9 million, primarily due to a $3.4 million increase in PCA fixed cost deferral revenues. The decreasecurrent year amortization of prior year under-collection, which was driven by higher amortization rates, offset in delivery deferral revenues resulted from a more significant decline in allowed revenues than actual revenues year-over-year, attributable to lower allowed rate per customer. For PCA fixed cost deferrals, actual revenues declined significantly, attributable to lower rates, partially offsetpart by increaseddecreased usage, as noted above in the retail revenue section, resulting in less over collection in the current year than in the prior year.

Othersales section. In addition, other decoupling revenue increased $3.6 million, primarily due to a $7.4 million increase year-over-year related to a decrease in current year amortization of previous years' decoupling deferrals. This resulted from lower amortization rates, partially offset by increased usage. This increase was offset in part by a $4.1 million decreaserevenues related to earnings in excess of allowed ROR.rate of return declined year-over year. In 2018, earnings in excess of allowed ROR of $7.52019, $2.7 million was returnedpassed back to customers, as compared to $3.5 million returnedcustomers; in the current year.
year period, there were no pass backs.
•Transportation and other revenue increased $99.5 decreased $86.4 million primarily due to an increasea decrease in net wholesale non-core natural gas sales of $84.4$91.6 million and a reductiondecrease in production tax credit (PTC) deferral revenue of $3.6 million for the re-purpose of the PTCs; partially offset by an increase if tax reform deferrals in 2020 for revenue subject to refunds of $32.2 million; partially offset by a change in PTC deferral revenue of $18.5 million for the re-purpose of the PTCs.$6.6 million. The increasedecrease in net wholesale non-core gas sales was due to an approximately 143% increase84% decrease in the average price of the non-core gas sold in 2019 as2020 compared to 2018, offset by2019 and a 12%24% decrease in sales volume andresulting in a $32.0$125.7 million increasedecrease in sales, offset by a $36.0 million decrease in the total cost of the non-core gas sold due to an approximately 67% increase in the average cost of the gas sold driven by an increase55% decrease in the average price of non-core gas purchases. The higherNatural gas prices occurredtrended down in early2020 due to a combination of high gas production, mild winter weather and surplus storage, while the 2019 andgas prices were very high due to the continuing effectseffect of the late 2018 Enbridge pipeline rupture in late 2018 which led to a decrease in pipeline capacity in the region at the same time that there werewas compressor issues at a gas storage facility which limited naturallimiting gas deliverability, and higher than expected load due to the cold weather during that time.
in 2019. Also contributing to the net decrease in wholesale non-core gas sales was a $1.5 million increase gas hedging costs.


Electric Power Costs
Electric power costs increased $134.2 decreased $118.1 million primarily due to an increasea decrease of $69.9$105.0 million of purchased electricity costs and an increase of $65.3$13.6 million of electric generation fuel expense.expenses. These items are discussed in detail below:below.
•Purchased electricity expense increased $69.9decreased $105.0 million primarily due to a 30.8% increase in wholesale prices partially offset by an 11.4%19.2% decrease in wholesale electricity purchases.purchases and a 24.3% decrease in wholesale prices. The decrease in purchases was primarily driven by a decrease in hydro purchases at Mid-Columbiaload and a decrease in other contracted resources and non-firm energy of 27.0%30.0% and 24.0%, due to unfavorable hydro conditions,respectively, driving an 69.4% increase in combustion turbine generation, which decreased the need to purchase additional wholesale power. During the 1st quarter of 2019, wholesale prices increased due to spot power prices at Mid-Columbia hit an 18-year high largely driven by record-breaking natural gas prices.
generation.
•Electric generation fuel expense increased $65.3decreased $13.6 million primarily due to a $49.6$8.1 million increasedecrease in Colstrip related to the retirement of Units 1 and 2 and a $5.4 million decrease in combustion turbine generation costs primarily driven by an increasea 46.8% in generationcost of 46.0% asnatural gas. Natural gas prices trended down in 2020 due to a resultcombination of favorable heat rates, unfavorable wholesale electricityhigh gas production, mild winter weather and surplus storage, while the 2019 gas prices reduced hydro purchaseswere very high due to the effect of 27.0%the Enbridge pipeline rupture in late 2018 which led to a decrease in pipeline capacity in the region at the same time that there was compressor issues at a gas storage facility limiting gas deliverability, and reduced hydro and wind generation of 21.6% and 12.9%, respectively.
higher than expected load due to the cold weather in 2019..


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

50

The following chart displays the details of PSE's natural gas margin changes for the three months ended September 30, 2018March 31, 2019 and 2019:2020:
chart-c98e25c3f61257fcb55.jpgpsd-20200331_g4.jpg
_______________
* Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Three months ended September 30, 2018Months Ended March 31, 2019 compared to 20192020
Natural Gas Operating Revenue
Natural gas operating revenueincreased $1.4$66.4 million primarily due to an increase of $3.3$42.6 million in total retail sales, an increase of $5.7 million in decoupling revenue, an increase of $18.0 million in other decoupling revenue and an increase of transportation and other revenue of $1.4 million; partially offset by a decrease of $1.7 million in decoupling revenue and a decrease of $1.6 million in total retail sales.revenue. These items are discussed in detail below.
•Natural gas retail sales revenue decreased $1.6 increased $42.6 million due to a decreasean increase in rates of $6.8$57.4 million partially offset by an increasea decrease in natural gas load of 5.0%4.5%, or $5.2$14.8 million of natural gas sales. Natural gas load increaseddecreased primarily due to the increasea 5.3% decrease in average therms used perby residential customers and a 3.3% decrease by commercial and industrialfirm customers, of 3.7%, 6.2% and 63.8%, respectively compared to 2018, as2019, attributable to a result of a 1.3% increase3.5% decrease in natural gas customers, which increased the natural gas heating load compared to prior year.degree days. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes.
•Decoupling revenue decreased $1.7 million. This is increased $5.7 million, primarily attributable to a higher allowed rate per customer and decreased usage, as noted above in the retail sales revenue section. This resulted in allowed natural gas revenues being greater than actual natural gas revenues in the current year, whereas they were less than actual natural gas revenues in the prior year.
•Other decoupling revenue increased $18.0 million, primarily due to an increase of $19.8 million attributable to lower current year amortization of prior year overcollection, resulting from lower amortization rates and decreased usage, as noted above in the retail revenue section. This resultedwas offset by a $1.8 million decline related to earnings in actual natural gas revenues being greater thanexcess of allowed natural gas revenuesrate of return. In 2019, $1.8 million was passed back to customers; in the current year, where as in the prior year allowed natural gas revenuesthere were greater than actual natural gas revenues.no pass backs.

51

Other decoupling revenue increased $3.3 million, primarily due to a $3.8 million increase year-over-year related to a decrease in current year amortization of previous years' decoupling deferrals resulting from lower amortization rates, partially offset by increased natural gas usage in the current year.
Transportation and other revenue increased $1.4 million primarily due to a decrease of tax reform deferrals returned to customers for revenue subject to refund in 2019 of $1.0 million.


Natural Gas Energy Costs
Purchased natural gas expense decreased $2.4increased $55.5 million due to an increase in the PGA rates in November 2019 and the addition of two supplemental gas commodity costs amortization rates in 2019 which were added in order to recover the large amount of gas costs that PSE incurred in late 2018 and early 2019 due to the Enbridge pipeline explosion; partially offset by a decrease in natural gas costs included in PGA rates partially offset by an increase in natural gas usage of 5.0%4.5%. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.


The following chart displays the details of PSE's natural gas margin changes for the nine months ended September 30, 2018 and 2019:
chart-0562bf3f2e8e5b18957.jpg
_______________
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.

Nine months ended September 30, 2018 compared to 2019
Natural Gas Operating Revenue
Natural gas operating revenue decreased $31.0 million primarily due to a decrease of $37.2 million in total retail sales due to a decrease of natural gas rates and a decrease of $5.5 million in other decoupling revenue, partially offset by an increase in transportation and other revenue of $11.9 million. These items are discussed in detail below.
Natural gas retail sales revenue decreased $37.2 million due to a decrease in rates of $63.6 million, offset by an increase in natural gas load of 4.1%, or $26.4 million in natural gas sales. Natural gas load increased primarily due to the increase in average therms used per residential, commercial and industrial customers of 4.7%, 4.2%, and 6.4%, respectively, compared to 2018 as a result of a 3.4% increase in heating degree days in the 1st quarter of 2019 as well as 1.3% increase in natural gas customers. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.
Other decoupling revenue decreased $5.5 million,primarily due to 2018 estimated earnings in excess of allowed ROR being trued up to match actual earnings in excess of allowed ROR by $3.4 million whereas no such true up occurred in the current year. In addition, current year amortization of previous years' decoupling deferrals increased year-over-year, resulting in a decrease of $2.4 million, attributable to higher amortization rates and increased natural gas usage in the current year.

Transportation and other revenue increased $11.9 million primarily due to tax reform deferrals returned to customers for revenue subject to refund of $12.2 million.

Natural Gas Energy Costs
Purchased natural gas expense decreased $43.4 million due to a decrease in natural gas costs included in PGA rates partially offset by an increase in natural gas usage of 4.1%. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.

Other Operating Expenses and Other Income (Deductions)
The following chart displays the details of PSE's operating expenses and other income (deductions) for the three months ended September 30, 2018March 31, 2019 and 2019:2020:


chart-46d33384b19050e7b47.jpgpsd-20200331_g5.jpg
52

Three months ended September 30, 2018Months Ended March 31, 2019 compared to 20192020
Other Operating Expenses
•Net unrealized (gain) loss on derivative instruments decreased $28.8$63.7 million to a net loss of $14.7 million. The primary$48.5 million for the quarter ended March 31, 2020. One of the drivers for the change related to a decrease in the overall weighted average forward prices resulting in a $25.5 million decrease. Additionally, the change from net settlements of electric and natural gas trades previously recorded as $4.5$44.3 million in gains and $1.2$17.2 million in losses, respectively, further reducedrespectively. The other driver related to the net unrealized (gain) loss.
change in the weighted average forward prices for electric and natural gas. Specifically, electric prices decreased 28.09% resulting in $83.3 million loss for electricity. Gas price decreased 31.39% resulting in $41.9 million loss for natural gas.
•Utility operations and maintenance expense increased $3.5decreased $3.0 million primarily due to an increasea decrease in (i) hardware and software maintenance costs and ITelectric bad debt expense of $3.5 million due to an increase in IT projects; (ii) an increase in damage and liability claims of $2.2 million; and (iii) an increase of $1.5 million of transformer and overhead line expense; partially offset by (iv) a decrease of $4.1 million of bad debt expense due to an improved collection process.
Non-Utilityprocess and other expense increased $1.3 million primarily due to an increase in the long-term incentive plan accruallower software and hardware maintenance contracts of $3.9$0.9 million due to an increase in long-term incentive plan awards in 2019 partially offset by a decrease in biogas gas purchase expense of $3.0 million.
savings as well as timing;

•Depreciation and amortization expense decreased $15.3$21.8 million primarily driven by: (i) aelectric amortization decreased by $14.7 million or 41.2% from 2019. The decrease is primarily driven by the $2.4 million in deferral treatment of meter assets amortization effective March 1, 2019, as submitted to Washington Commission and $6.4 million in amortization of PTCfor the regulatory liability of $8.5 million in 2019 as compared to 2018,associated with revised power cost Schedule 95 effective July 1, 2019.; (ii) a decrease of $7.6 million inconservation amortization decreased by $5.9 million; (iii) common amortization duedecreased by $4.7 million or 20.0% from 2019. The decrease is primarily driven by the $9.6 million in deferral treatment of IT amortization effective May 1, 2019, as submitted to the Washington Commission (iii) a decrease of $4.9but offset by $78.0 million for amortization ofin net additions to computer software. Additionally, the Microsoft transition fee set in rates by a Washington Commission order, (iv) a decrease in electric amortization driven by the deferral treatment of $4.6 million for meter assets effective April 1, 2019 as submitted to the Washington Commission, (v) a decrease in conservation amortization of $3.9 million;decreases were partially offset by (vi) an(iv) electric distribution depreciation increased a net of $2.3 million or 6.8% from 2019. The increase in common amortization of $8.1is primarily due to $146.6 million driven byin net additions of $129.9electrical distribution assets; and (v) natural gas distribution depreciation increased by $2.0 million of software; (vii) electric depreciation expense increased $4.1or 7.4% from 2019. The increase is primarily due to $249.0 million in net additions in natural gas distribution assets.
•Taxes other than income taxes decreased $3.2 million primarily due to net asset additions to distribution of $213.6 million and (viii) an increase in natural gas depreciation expense of $2.1 million primarily due to net asset additions to distribution of $210.5 million offset by a depreciation rate change to a lower rate.
Taxes other than income taxes decreased $2.1 million primarily due to decreases in municipal taxes of $1.3 million and state excise taxes of $0.8 million as a result of a decrease in retail revenue, as well as a decrease of $0.4$2.6 million related to the property tax tracker.
tracker due to load.


Other Income, Interest Expense and Income Tax Expense 
Interest expense increased $3.0 million primarily related to PSE's issuance of $450.0 million of senior notes at an interest rate of 3.25%. For additional information, see Note 10, "Other" to the consolidated financial statements included in Item 1 of this report.
•Income tax expense decreased $3.3$5.6 million primarily driven by a decrease in pre-tax income.


53


The following chart displays the details of PSE's operating expenses and other income (deductions) for the nine months ended September 30, 2018 and 2019:

chart-7c520d73fe3a5fa2bee.jpg

Nine months ended September 30, 2018 compared to 2019
Other Operating Expenses
Net unrealized (gain) loss on derivative instruments decreased $51.8 million to a net loss of 29.9 million. The primary drivers for the change related to net settlements of $50.9 million and $22.9 million of electric and natural gas trades previously recorded as gains. However, these settlements were offset by an increase in gains due to an increase in the overall weighted average forward prices, resulting in a $22.0 million increase.
Utility operations and maintenance expense increased $10.2 million primarily due to an increase in (i) hardware and software maintenance costs and IT expense of $9.6 million due to an increase in IT projects, (ii) non-deferred storm costs of $4.9 million primarily related to first quarter storms; and (iii) an increase in AMI meter reading costs of $1.7 million; (iv) an increase in damage and liability claims of $1.7 million; and (v) an increase in wild horse maintenance costs of $1.6 million due to normal cycled maintenance every 3-5 years; partially offset by (vi) a decrease of $5.0 million of bad debt expense due to an improved collection process and (vii) a decrease in underground cable expense of $3.3 million.
Non-utility and other expense increased $3.9 million primarily due to an increase in the long-term incentive plan accrual of $6.5 million due to an increase in long-term incentive plan awards in 2019 partially offset by a decrease in biogas gas purchase expense of $2.9 million.
Depreciation and amortization expense decreased $14.1 million primarily driven by: (i) a decrease in amortization of PTC regulatory liability of $18.5 million in 2019 as compared to 2018, (ii) a decrease of $12.9 million in common amortization due the deferral treatment of IT amortization effective May 1, 2019 as submitted to the Washington Commission, (iii) a decrease of $4.9 million for amortization of the Microsoft transition fee set in rates by a Washington Commission order, (iv) a decrease in electric amortization driven by the deferral treatment of $8.4 million for meter assets effective April 1, 2019 as submitted to the Washington Commission, (v) a decrease in conservation amortization of $11.4 million due to lower rates in 2019 as compared to 2018; partially offset by (vi) an increase in common amortization of

$29.1 million driven by net additions of $129.9 million of software; (vii) electric depreciation expense increased $7.9 million primarily due to net asset additions to distribution of $213.6 million and (viii) an increase in natural gas depreciation expense of $5.8 million primarily due to net asset additions to distribution of $210.5 million.
Taxes other than income taxes decreased $8.0 million primarily due to decreases in municipal taxes of $4.6 million and state excise taxes of $3.1 million as a result of a decrease in retail revenue, as well as a decrease of $2.2 million related to the property tax tracker.

Other Income, Interest Expense and Income Tax Expense    
Other Income/expense increased $8.0 million primarily due to a $4.5 million increase in PGA interest income driven by a larger under-recovery compared to an over-recovery in 2018 and a $4.7 million increase in allowance for funds used during construction (AFUDC) driven by a change in the rate and an increase in eligible construction work in progress.
Interest expense increased $5.8 million primarily related to PSE's issuance of $450.0 million of senior notes at an interest rate of 3.25%. For additional information, see Note 10, "Other" to the consolidated financial statements included in Item 1 of this report.
Income tax expense decreased $10.9 million primarily driven primarily driven by a decrease in pre-tax income.

Puget Energy
Primarily, all operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three months ended September 30, 2018March 31, 2019 and 2019 are2020, is as follows:


chart-25790516d3c8515c9c0.jpgpsd-20200331_g6.jpg

Three months ended September 30, 2018Months Ended March 31, 2019 compared to 20192020
Summary Results of Operation
Puget Energy’s net income decreased for the three months ended September 30, 2019March 31, 2020, by $17.4$37.3 million primarily due to a decrease in PSE's net income compared to the same period in the prior year.



Puget Energy's net income (loss) for the nine months ended September 30, 2018 and 2019 are as follows:

chart-f140ab5ea9525b5891b.jpg


Nine months ended September 30, 2018 compared to 2019
Summary Results of Operation
Puget Energy’s net income decreased for the nine months ended September 30, 2019 by $68.8 million primarily due to a decrease in PSE's net income compared to the same period in the prior year partially offset by an increase in interest expense of $3.6 million, as Puget Energy entered into a new $210.0 million term loan agreement and an additional $24.0 million of supplemental loans under the expansion feature of the existing term loan agreement during 2019. For additional information, see Note 10, "Other" to the consolidated financial statements included in Item 1 of this report.

Capital Requirements
Contractual Obligations and Commercial Commitments
During the nine months ended September 30, 2019, there were no material changesIn addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, during the three months ended March 31, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $473.7 million through 2037.
For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2018.2019.

54

The following are the Company's aggregate availability under commercial commitments as of September 30, 2019:March 31, 2020:
Puget Energy and
Puget Sound Energy		Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)Total20202021-20222023-2024Thereafter
Commercial commitments:
PSE revolving credit facility$740,000  $—  $—  $740,000  $—  
Inter-company short-term debt30,000  —  —  —  30,000  
Total PSE commercial commitments770,000  —  —  740,000  30,000  
Puget Energy revolving credit facility768,500  —  —  768,500  —  
Less: Inter-company short-term debt elimination(30,000) —  —  —  (30,000) 
Total Puget Energy commercial commitments$1,508,500  $—  $—  $1,508,500  $—  
Puget Energy and
Puget Sound Energy		Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)Total 2019 2020-2021
 2022-2023
 Thereafter
Commercial commitments:         
PSE revolving credit facility$800,000
 $—
 $—
 $800,000
 $—
Inter-company short-term debt30,000
 —
 —
 —
 30,000
Total PSE commercial commitments$830,000
 $—
 $—
 $800,000
 $30,000
Puget Energy revolving credit facility783,100
 —
 —
 783,100
 —
Less: Inter-company short-term debt elimination(30,000) —
 —
 —
 (30,000)
Total Puget Energy commercial commitments$1,583,100
 $—
 $—
 $1,583,100
 $—


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


Off-Balance Sheet Arrangements
As of September 30, 2019,March 31, 2020, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.


Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements, support customer growth and to improve energy system reliability.  Construction expenditures, excluding equity AFUDC,allowance for funds used during construction (AFUDC), totaled $680.1$225.6 million for the ninethree months ended September 30, 2019.March 31, 2020. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Millions)202020212022
Total energy delivery, technology and facilities expenditures$965.5$1,031.1$1,023.7
Capital Expenditure Projections     
(Dollars in Thousands)2019 2020 2021
Total energy delivery, technology and facilities expenditures$885,623
 $916,545
 $895,610


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.  

55



Capital Resources
Cash from Operations
Puget Sound Energy Nine Months Ended
September 30,		Puget Sound EnergyThree Months Ended
March 31,
(Dollars in Millions)2019 2018 Change
(Dollars in Thousands)(Dollars in Thousands)20202019Change
Net income$123,720
 $193,709
 $(69,989)Net income$111,321  $147,302  $(35,981) 
Non-cash items1
531,225
 493,821
 37,404
Non-cash items1
215,063  188,451  26,612  
Changes in cash flow resulting from working capital2
(163,835) 158,184
 (322,019)
Changes in cash flow resulting from working capital2
24,754  60,743  (35,989) 
Regulatory assets and liabilities(46,993) (22,545) (24,448)Regulatory assets and liabilities(16,865) (15,838) (1,027) 
Purchased gas adjustmentPurchased gas adjustment41,429  (137,092) 178,521  
Other non-current assets and liabilities3
(13,028) (8,356) (4,672)
Other non-current assets and liabilities3
(23,801) (11,959) (11,842) 
Net cash provided by operating activities$431,089
 $814,813
 $(383,724)Net cash provided by operating activities$351,901  $231,607  $120,294  
_______________
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.

1 Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and
Nine months ended September 30, 2019other miscellaneous non-cash items.
2 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayment, PGA, accounts
payable and accrued expenses.
3 Other non-current assets and liabilities include funding of pension liability.

Three Months Ended March 31, 2020 compared to 20182019
Cash generated from operations for the ninethree months ended September 30, 2019 decreasedMarch 31, 2020 increased by $383.7$120.3 million including a net income decrease of $70.0$36.0 million. The following are significant factors that impacted PSE's cash flows from operations:
•Cash flow adjustments resulting from non-cash items increased $37.4$26.6 million primarily due to a $51.8$63.7 million change from a net unrealized gain on derivative instruments of $22.0$15.2 million to a net unrealized loss on derivative instruments of $29.9 million, as well as a decrease in production tax credit monetization of $20.7$48.5 million, offset by decreases in depreciation and amortization of $2.7$15.9 million, amortization of TCJA Over Collection of $10.6 million, conservation amortization of $11.4$5.9 million, and deferred income taxes of $14.4$7.1 million. For further details, see Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.
•Cash flows resulting from changes in working capital decreased $322.0 million partly due to changes$36.0 million. Cash outflow in purchased gas adjustments of $165.7 million caused by actual natural gas costs being above natural gas baseline rates in the PGA mechanism. For further details, see Management's Discussion and Analysis, "Natural Gas Margin" in Item 2. In addition, Accounts payable increase in cash outflow of $122.9increased $81.9 million, which was primarilymainly due to payment of significant power and natural gas costs accrued at December 31, 20182019 that were paid in 2019. Finally,2020. The increase of cash outflows associated with taxesoutflow in Account payable increasedwas partially offset by $47.8$45.6 million as property taxes were paidincrease of cash inflow in September of 2019 as compared to October of 2018.Account receivable.
•Cash flowsflow resulting from regulatorypurchased gas adjustment (long-term) increased $178.5 million primarily due to actual natural gas costs were above natural gas baseline rates in the PGA mechanism in 2019 primarily due to a PGA rate increase in November 2019.
•Cash flow resulting from changes in other non-current assets and liabilities decreased $24.4$11.8 million primarily due to an increasedecrease in the power cost adjustment mechanism due to actual power costs being above power baseline costs. For further details, see Management's DiscussionSERP liability offset with other changes in long-term assets and Analysis, "Electric Margin" in Item 2.liabilities.

Puget EnergyNine Months Ended
September 30,		Puget EnergyThree Months Ended
March 31,
(Dollars in Millions)2019 2018 Change
(Dollars in Thousands)(Dollars in Thousands)20202019Change
Net income$(63,961) $(65,138) $1,177
Net income$(16,385) $(15,148) $(1,237) 
Non-cash items1
5,990
 616
 5,374
Non-cash items1
(932) (5,260) 4,328  
Changes in cash flow resulting from working capital2
(10,938) 2,058
 (12,996)
Changes in cash flow resulting from working capital2
(19,998) (11,498) (8,500) 
Regulatory assets and liabilities—
 —
 —
Other noncurrent assets and liabilities3
(8,047) (10,016) 1,969
Other non-current assets and liabilities3
Other non-current assets and liabilities3
(3,215) (1,504) (1,711) 
Net cash provided by operating activities$(76,956) $(72,480) $(4,476)Net cash provided by operating activities$(40,530) $(33,410) $(7,120) 
_______________
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 non-current 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.
Nine months ended September 30, 20192 Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, PGA, accounts payable and accrued expenses.
3Other noncurrent assets and liabilities include funding of pension liability.
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Three Months Ended March 31, 2020 compared to 20182019
Cash generated from operations for the ninethree months ended September 30, 2019,March 31, 2020, in addition to the changes discussed at PSE above, decreased by $4.5$7.1 million compared to the same period in 2018.2019, which includes a net income decrease of $1.2 million.  The remaining change was primarily impacted by the factors explained below:
•Non-cash items increased $4.3 million due to changes in deferred taxes.
•Cash flow resulting from non-cash items increased $5.4working capital decreased $8.5 million primarily due to changes in deferred income taxes.Account payable.
Cash flow resulting from working capital decreased $13.0 million primarily due to changes in eliminations of PSE's intercompany account receivable balances with PLNG.

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

As a result of the COVID-19 outbreak and its impact on the economy and capital markets, the Company is carefully monitoring cash receipts from customers and any impacts on the Company’s liquidity which may affect its ability to fund safe, reliable and dependable service for our customers. Our initiative to suspend disconnections of customers for non-payment, the receipt of the Washington Commission approval to waive late fees, and our request of, the Washington Commission to waive the statutory deadline for the Company’s General Rate Case for up to 60 days, from May 20, 2020, until July 20, 2020, will likely impact future cash receipts. In addition, commercial paper markets were significantly impacted for a period of time due to COVID-19, which limited commercial paper borrowings and alternatively the Company drew short term funding from its credit facility. The commercial paper market, while somewhat improved, has not returned to pre-COVID-19 conditions. In the future, the Company expects to draw on its credit facility and will access commercial paper markets when it is able to do so. To ensure the Company’s liquidity during the economic uncertainty, since April 1, 2020, the Company has maintained a minimum cash reserve of $100 million, which is intended to be utilized to cover cash disbursements in the event of illiquid markets. The Company will rely on its credit facilities and, when available, the commercial paper markets to fund the minimum cash reserve. Evolving factors that we cannot accurately predict, including the duration and scope of the pandemic, and any relevant governmental, business and customers’ actions that have been and continue to be taken in response to the pandemic, could negatively impact the Company’s liquidity.

Puget Sound Energy
Credit Facility
As of September 30, 2019,March 31, 2020, PSE had an $800.0 million credit facility to meet short-term liquidity needs. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of theThe unsecured revolving credit facility was extended for one year. The facility now matures in October 2023.
The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2019,March 31, 2020, PSE was in compliance with all applicable covenant ratios.
The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.
As of September 30, 2019, no amounts wereMarch 31, 2020, $60.0 million was drawn and outstanding under PSE's credit facility and $69.0$16.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.8 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.



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Demand Promissory Note
In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of September 30, 2019,March 31, 2020, PSE had no outstanding balance under the Note.


Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests at September 30, 2019,March 31, 2020, PSE could issue:
•Approximately $1.8$2.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on

approximately $3.0$3.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at September 30, 2019;March 31, 2020; and
•Approximately $591.0$726.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $985.0 million$1.2 billion of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30, 2019.March 31, 2020.
At September 30, 2019,March 31, 2020, PSE had approximately $7.6$7.8 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.


Shelf Registrations
On August 2, 2019, PSE filed a new shelf registration statement for under which it may issue, up to $1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration.to be issued. The shelf registration will expire in August 2022.


Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At September 30, 2019,March 31, 2020, approximately $816.5 million$1.0 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 48.4%49.5% at September 30, 2019March 31, 2020, and the EBITDA to interest expense was 5.3 to 1.0 for the twelve months ended September 30, 2019.March 31, 2020.
PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. At March 31, 2020, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


Long-TermLong Term Debt
On August 30, 2019, PSE issued $450.0 million of senior notes at an interest rate of 3.25%.  The notes pay interest semi-annuallyCompany had no new long-term debt activities in the three months ended March 31, 2020. For further information, see Note 7, "Long-Term Debt" and are due to matureNote 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on September 15, 2049. Proceeds fromForm 10K for the sale of the notes were used to repay outstanding short term debt under the Company’s commercial paper program.year ended December 31, 2019.

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Puget Energy
Credit Facility
As of September 30, 2019,At March 31, 2020, Puget Energy maintained an $800.0 million credit facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of theThe unsecured revolving credit facility was extended for one year. The facility now 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, 2019,March 31, 2020, there was $16.9$31.5 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of September 30, 2019,March 31, 2020, Puget Energy was in compliance with all applicable covenants.



Long-Term Debt
In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans underThe Company had no new long-term debt activities in the expansion feature of the term loan agreement with the existing lenders. All other termsthree months ended March 31, 2020. For further information, see Note 7, "Long-Term Debt" and conditions of the agreement remain unchanged. The proceeds from the term loanNote 8, "Liquidity Facilities and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.
On September 26, 2019, Puget Energy entered into a separate $210.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loansOther Financing Arrangements" in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program.most recent Annual Report on Form 10K for the year ended December 31, 2019.


Dividend Payment Restrictions
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.6 to 1.0 for the twelve months ended September 30, 2019.March 31, 2020.
At September 30, 2019,March 31, 2020, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


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


Washington Clean Energy TransitionTransformation 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 TransitionTransformation Act requires all electric utilities to eliminate coal-fired generation from their allocation of electricity by December 31, 2025; to be carbon-neutral by January 1, 2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and makes it the state policy that, by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean Energy Implementation plans are required every four years from each investor-owned utility (IOU), and each IOU must propose interim targets for meeting the 2045 standard between 2030 and 2045, and lay out an actionable plan that they intend to pursue to meet the standard. The Washington Commission may approve, reject, or recommend alterations to an IOU’s plan.
In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive-based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow investor-owned utilitiesIOUs to recover costs in rates for earlier closure of those facilities. Investor-owned utilitiesIOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPA's)(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,2% threshold for alternative compliance, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.

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

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected

shutdown date. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.
OnConsistent with a June 11, 2019 announcement, Talen made a public announcement that Colstrippermanently shut down Units 1 and 2 will be shut down at the end of the year due to operational losses associated with the Units. The regulatory asset associated with early retirement of Colstrip Units 1 and 2 increased from $130.7 million as ofwere retired effective December 31, 2018, to $178.2 million as of September 30, 2019. The Washington Clean Energy TransitionTransformation Act requires the Washington Commission to provide recovery of the undepreciated investment and to allow in electric rates all prudently incurred decommissioning, and remediation costs associated with the facilities. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. PSE filed an application seeking approval of the sale from the Washington Commission on February 20, 2020. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. For accounting purposes, management has evaluated the applicable held for sale criteria as of March 31, 2020, and determined that these criteria were not met. As such, Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet.

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


Clean Air Act 111(d)/EPA Affordable Clean Energy RulePower Plan
In October 2015,June 2014, the EPA issued thea proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants, which includedplants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. However, after signingThe EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in MarchOctober 2017, the EPA finalized a ruleproposed to repeal the CPP rule in June 2019rule.
In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to replaceSection 111(d) of the 2015 CPP.Clean Air Act. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. Compliance plans under ACE are due July 2022, and compliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations.operations pending the outcome of the proposed Colstrip Unit 4 sale to NorthWestern Energy.


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Washington Clean Air Rule
The CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019,2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but no determination byremanded the case back to the Thurston County to determine which parts of the rule survive. Ecology and the four parties asked Thurston County to stay this case until the 2020 Washington State legislative session concluded and now Ecology plans to ask the court has yet been made. Theto extend the stay until the COVID-19 pandemic is over. Meanwhile, the four companies moved to voluntarily dismiss the federal court litigation has been heldwithout prejudice in abeyance pending resolution of the state case.March 2020.


Related Party Transactions
In August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. Following a mediation process and the filing of a settlement stipulation by PSE and all parties, the Washington Commission issued an order on October 31, 2016, that allowed PSE’s parent company, Puget Energy, to create a wholly-owned subsidiary, named Puget LNG, which was formed on November 29, 2016, for the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility. Puget LNG has entered into one fuel supply agreement with a maritime customer and is marketing the facility’s expected output to other potential customers.
The Tacoma LNG facility is currently under construction. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. Per this allocation of costs, $191.8$198.0 million of construction work in progress and $1.0$0.3 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of September 30, 2019.March 31, 2020. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.


IBEW Union Contract

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


Item 3.  Quantitative and Qualitative Disclosure about Market Risk


The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.2019.


Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy
61

Management Committee establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.    
PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  


Counterparty Credit Risk
PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. PSE manages credit risk with policies and procedures for counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB)) with its counterparties to mitigate credit exposure.
Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. During periods of financial market or interest rate volatility, the Company may utilize its credit facilities for short term funding needs instead of the commercial paper program.Credit facility borrowings are based on a more stable base rate and the credit spread is fixed
Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also enter into swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.


Item 4.  Controls and Procedures


Puget Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 2019,March 31, 2020, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.


Changes in Internal Control over Financial Reporting
During 2018, PE implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.
There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended September 30, 2019March 31, 2020 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.



Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 2019,March 31, 2020, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.


Changes in Internal Control over Financial Reporting
During 2018, PSE implemented internal controls covering the evaluation and assessment of leasing contracts related to the adoption of the new leasing standard as of January 1, 2019.
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There have been no changes in PSE’s internal control over financial reporting during the quarter ended September 30, 2019March 31, 2020 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.



PART II            OTHER INFORMATION


Item 1.   Legal Proceedings


Contingencies arising out of the Company's normal course of business existed as of September 30, 2019.March 31, 2020.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements in Item I.


Item 1A.  Risk Factors


There have been noThe following represents a material changes from thechange in our risk factors set forthfrom those disclosed in Part I,1, Item 1A "Risk Factors" of the Company's Annual Report onour Form 10-K for the periodyear ended December 31, 2018.2019.


PSE faces risks related to health epidemics such as the novel Coronavirus (COVID-19) and other outbreaks that could have a material adverse impact on our business and results of operations. The recent outbreak of the COVID-19 has adversely impacted economic activity and conditions worldwide. We cannot predict the degree that the continued spread of COVID-19 and efforts to contain the virus (including, but not limited to, voluntary and mandatory quarantines, restrictions on travel, limiting gatherings of people, and reduced operations and extended closures of many businesses and institutions) could materially impact our results of operations, financial condition and ongoing operations. The impacts include but are not limited to:
•impacting customer demand for electricity and natural gas by our customers, particularly from commercial and industrial customers;
•reducing the availability and productivity of our employees;
•causing us to experience an increase in costs as a result of our emergency measures, delayed payments from our customers and uncollectible accounts;
•causing delays and disruptions in the availability of and timely delivery of materials and components used in our operations;
•causing a deterioration in our financial metrics or the business environment that impacts our credit ratings;
•causing significant disruption in the financial markets which could have a negative impact on our ability to access capital in the future and cost of capital;
•resulting in our inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding the ratio of total debt to total capitalization; and
•disrupting our ability to meet customer requirements and potentially significantly increase response costs.


Item 6.   Exhibits


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





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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).
Term Loan Agreement, dated as of September 26, 2019. by and among Puget Energy, as borrower, Mizuho Bank as Administrative Agent and Mizuho Bank, U.S. Bank and Co-Bank as lenders.
10.2*
Employment Offer Letter, dated as of June 20, 2019, by and between Puget Sound Energy, Inc. and Mary E. Kipp.
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.
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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, 2019March 31, 2020 filed on November 6, 2019May 06, 2020 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
__________________
*
Filed herewith.

*Filed herewith.



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SIGNATURES


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


PUGET ENERGY, INC.

PUGET SOUND ENERGY, INC.
 
/s/ Stephen King
Stephen King

Controller & Principal Accounting Officer
Date:  NovemberMay 6, 20192020





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