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, 20172019
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
pelogo2015q1a18.jpg
1-16305
PUGET ENERGY, INC.
A Washington Corporation
10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004
(425) 454-6363
91-1969407
pselogo2015q1a18.jpg
1-4393
PUGET SOUND ENERGY, INC.
A Washington Corporation
10885355 110th Ave NE 4th Street, Suite 1200
Bellevue, Washington 98004-559198004
(425) 454-6363
91-0374630
Securities Registered pursuant to Section 12(b) of the Securities Exchange Act of 1934
Title of each 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 and posted on their corporate websites, if any, every interactiveInteractive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Puget Energy, Inc.Yes/X/No/  / Puget Sound Energy, Inc.Yes/X/No/  /
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company.  See definitionthe definitions of “large accelerated filer", "accelerated filer, accelerated filer and" a smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Puget Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filer/X/Smaller reporting company/  /Emerging growth company/  /
Puget Sound Energy, Inc.Large accelerated filer/  /Accelerated filer/  /Non-accelerated filer/X/Smaller reporting company/  /Emerging growth company/  /
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /

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


Table of Contents

  Page
Definitions
3
Filing Format
4
Forward-Looking Statements
4
   
Part I.
Financial InformationInformation
5
   
Item 1.
Financial Statements
5
 Puget Energy, Inc. 
 
Consolidated Statements of Income – Three and Nine Months Ended September 30, 20172019 and 20162018
5
 
Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 20172019 and 20162018
6
 
Consolidated Balance Sheets – September 30, 20172019 and December 31, 20162018
7
 
Consolidated Statements of Common Shareholder's Equity - September 30, 2019 and December 31, 2018
8
Consolidated Statements of Cash Flows – Nine Months Ended September 30, 20172019 and 20162018
89
   
 Puget Sound Energy, Inc. 
 
Consolidated Statements of Income – Three and Nine Months Ended September 30, 20172019 and 20162018
910
 
Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 20172019 and 20162018
1011
 
Consolidated Balance Sheets – September 30, 20172019 and December 31, 20162018
1112
Consolidated Statements of Common Shareholder's Equity - September 30, 2019 and December 31, 2018
14
 
Consolidated Statements of Cash Flows – NineThree Months Ended September 30, 20172019 and 20162018
1315
   
 Notes 
 
Combined Notes to Consolidated Financial Statements
1416
   
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
35
   
Item 3.
Quantitative and Qualitative Disclosure About Market Risk
5361
   
Item 4.
Controls and Procedures
5361
   
Part II.
Other Information
5462
   
Item 1.
Legal Proceedings
5462
   
Item 1A.
Risk Factors
54
Item 5.Other Information
5462
   
Item 6.
Exhibits
5562
   
Exhibit Index
5663
  
Signatures
5764


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.



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;
●Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
●PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
●The ability to restart generation following a regional transmission disruption;
●The ability of a natural gas or electric plant to operate as intended;
●Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;
●The ability to renew contracts for electric and natural gas supply and the price of renewal;
●Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
●The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
●The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
●Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
●Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●Employee workforce factors, including strikes, work stoppages, 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.10-K for the year ended December 31, 2018.


PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

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



Three Months Ended September 30, Nine Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162019 2018 2019 2018
Operating revenue:              
Electric$537,543
 $495,321
 $1,736,335
 $1,622,664
$513,926
 $534,569
 $1,823,596
 $1,735,765
Natural gas111,516
 114,458
 691,685
 601,309
108,222
 106,826
 566,347
 597,306
Other11,318
 8,499
 29,356
 25,170
4,859
 10,069
 22,833
 28,253
Total operating revenue660,377
 618,278
 2,457,376
 2,249,143
627,007
 651,464
 2,412,776
 2,361,324
Operating expenses: 
  
  
  
 
  
    
Energy costs: 
  
  
  
 
  
    
Purchased electricity115,881
 94,849
 425,263
 356,296
107,035
 148,536
 501,738
 431,856
Electric generation fuel66,584
 70,503
 152,057
 165,627
93,642
 71,004
 208,442
 143,177
Residential exchange(14,246) (15,577) (52,814) (49,093)(15,295) (15,401) (56,430) (55,436)
Purchased natural gas32,224
 34,041
 248,208
 205,418
27,778
 30,192
 168,281
 211,679
Unrealized (gain) loss on derivative instruments, net(23) 6,327
 23,098
 (57,218)14,716
 (14,046) 29,861
 (21,953)
Utility operations and maintenance141,003
 138,265
 438,622
 422,273
142,857
 139,361
 450,236
 440,016
Non-utility expense and other7,319
 4,708
 18,658
 15,520
12,436
 19,338
 36,813
 40,587
Depreciation and amortization120,829
 110,022
 355,538
 328,809
138,281
 149,760
 483,693
 486,377
Conservation amortization25,395
 21,800
 85,847
 77,551
17,734
 21,601
 71,049
 82,489
Taxes other than income taxes66,367
 65,268
 262,099
 235,431
61,697
 63,822
 240,392
 248,357
Total operating expenses561,333
 530,206
 1,956,576
 1,700,614
600,881
 614,167
 2,134,075
 2,007,149
Operating income (loss)99,044
 88,072
 500,800
 548,529
26,126
 37,297
 278,701
 354,175
Other income (expense): 
  
  
  
 
  
    
Other income7,151
 6,130
 19,375
 19,187
15,439
 24,806
 44,442
 46,378
Other expense(2,878) (5,025) (6,134) (8,488)(2,023) (3,250) (5,624) (7,678)
Non-hedged interest rate swap (expense) income—
 563
 28
 (651)
Interest charges: 
  
  
  
 
  
    
AFUDC3,123
 2,702
 7,853
 7,663
3,732
 3,911
 10,652
 10,112
Interest expense(88,780) (89,297) (265,771) (266,786)(89,029) (87,578) (264,815) (261,988)
Income (loss) before income taxes17,660
 3,145
 256,151
 299,454
(45,755) (24,814) 63,356
 140,999
Income tax (benefit) expense4,824
 810
 80,489
 91,380
(6,312) (2,844) 3,597
 12,428
Net income (loss)$12,836
 $2,335
 $175,662
 $208,074
$(39,443) $(21,970) $59,759
 $128,571

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

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


Three Months Ended September 30, Nine Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162019 2018 2019 2018
Net income (loss)$12,836
 $2,335
 $175,662
 $208,074
$(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 $(143), $(16), $216 and $(216), respectively(266) (29) 400
 (400)
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)(266) (29) 400
 (400)(1,114) (2,786) (931) (7,563)
Comprehensive income (loss)$12,570
 $2,306
 $176,062
 $207,674
$(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
PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)



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



ASSETS
September 30,
2017		 December 31,
2016		September 30,
2019		 December 31,
2018
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):   
Utility plant (at original cost, including construction work in progress of $658,261 and $550,466, respectively):   
Electric plant$7,918,877
 $7,673,772
$8,738,072
 $8,515,482
Natural gas plant3,253,977
 3,051,586
3,824,045
 3,598,732
Common plant738,409
 594,994
1,084,309
 1,027,023
Less: Accumulated depreciation and amortization(2,409,508) (2,161,796)(3,157,819) (2,832,321)
Net utility plant9,501,755
 9,158,556
10,488,607
 10,308,916
Other property and investments: 
  
 
  
Goodwill1,656,513
 1,656,513
1,656,513
 1,656,513
Other property and investments166,996
 106,418
277,491
 244,444
Total other property and investments1,823,509
 1,762,931
1,934,004
 1,900,957
Current assets: 
  
 
  
Cash and cash equivalents6,768
 28,878
12,467
 37,521
Restricted cash9,302
 12,418
27,659
 18,041
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively232,699
 329,375
Accounts receivable, net of allowance for doubtful accounts of $7,608 and $8,408, respectively206,629
 338,782
Unbilled revenue126,252
 234,053
145,073
 205,285
Purchased gas adjustment receivable—
 2,785
155,711
 9,921
Materials and supplies, at average cost108,814
 106,378
120,143
 116,180
Fuel and natural gas inventory, at average cost60,645
 58,181
61,793
 53,351
Unrealized gain on derivative instruments16,605
 54,341
14,147
 46,507
Prepaid expense and other35,655
 43,046
28,502
 25,674
Power contract acquisition adjustment gain15,932
 33,413
8,281
 6,114
Total current assets612,672
 902,868
780,405
 857,376
Other long-term and regulatory assets: 
  
 
  
Regulatory asset for deferred income taxes71,566
 72,038
Power cost adjustment mechanism4,540
 4,531
24,810
 4,735
Regulatory assets related to power contracts19,998
 22,613
14,583
 16,693
Other regulatory assets1,014,796
 1,034,348
717,596
 773,552
Unrealized gain on derivative instruments2,877
 8,738
2,294
 2,512
Power contract acquisition adjustment gain163,588
 241,648
149,126
 156,597
Operating lease right of use asset168,491
 —
Other65,138
 58,109
86,841
 77,523
Total other long-term and regulatory assets1,342,503
 1,442,025
1,163,741
 1,031,612
Total assets$13,280,439
 $13,266,380
$14,366,757
 $14,098,861

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





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



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



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



CAPITALIZATION AND LIABILITIES
September 30,
2017		 December 31,
2016		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
3,308,957
 3,308,957
Retained earnings571,588
 413,468
652,006
 629,003
Accumulated other comprehensive income (loss), net of tax(33,312) (33,712)(78,133) (77,202)
Total common shareholder’s equity3,847,233
 3,688,713
3,882,830
 3,860,758
Long-term debt: 
  
 
  
First mortgage bonds and senior notes3,164,412
 3,362,000
4,212,000
 3,764,412
Pollution control bonds161,860
 161,860
161,860
 161,860
Junior subordinated notes250,000
 250,000
Long-term debt1,883,064
 1,812,480
2,200,900
 1,961,900
Debt discount, issuance costs and other(224,336) (234,679)(214,605) (215,681)
Total long-term debt5,235,000
 5,351,661
6,360,155
 5,672,491
Total capitalization9,082,233
 9,040,374
10,242,985
 9,533,249
Current liabilities: 
  
 
  
Accounts payable296,659
 317,043
288,126
 480,069
Short-term debt139,000
 245,763
69,000
 379,297
Current maturities of long-term debt200,000
 2,412
2,412
 —
Purchased gas adjustment payable5,784
 —
Accrued expenses: 
  
 
  
Taxes81,354
 111,428
74,971
 118,112
Salaries and wages41,121
 49,749
43,488
 50,785
Interest79,213
 73,610
81,038
 70,099
Unrealized loss on derivative instruments49,820
 44,310
30,504
 46,661
Power contract acquisition adjustment loss2,850
 3,159
2,473
 2,547
Operating lease liabilities15,173
 —
Other81,486
 71,996
104,132
 79,312
Total current liabilities977,287
 919,470
711,317
 1,226,882
Other long-term and regulatory liabilities: 
  
 
  
Deferred income taxes1,652,573
 1,570,931
808,636
 789,297
Unrealized loss on derivative instruments15,578
 16,261
18,222
 11,095
Regulatory liabilities611,899
 654,622
710,572
 747,203
Regulatory liability for deferred income taxes952,828
 975,974
Regulatory liabilities related to power contracts179,519
 275,061
157,407
 162,711
Power contract acquisition adjustment loss17,148
 19,454
12,110
 14,146
Operating lease liabilities159,913
 —
Other deferred credits744,202
 770,207
592,767
 638,304
Total other long-term and regulatory liabilities3,220,919
 3,306,536
3,412,455
 3,338,730
Commitments and contingencies (Note 8)

 



 

Total capitalization and liabilities$13,280,439
 $13,266,380
$14,366,757
 $14,098,861

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

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

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



 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) $—

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



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


Three Months Ended September 30, Nine Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162019 2018 2019 2018
Operating revenue:              
Electric$537,543
 $495,321
 $1,736,335
 $1,622,664
$513,926
 $534,569
 $1,823,596
 $1,735,765
Natural gas111,516
 114,458
 691,685
 601,309
108,222
 106,826
 566,347
 597,306
Other11,318
 8,815
 29,356
 25,487
4,859
 10,069
 22,833
 28,253
Total operating revenue660,377
 618,594
 2,457,376
 2,249,460
627,007
 651,464
 2,412,776
 2,361,324
Operating expenses: 
  
     
  
    
Energy costs: 
  
     
  
    
Purchased electricity115,881
 94,849
 425,263
 356,296
107,035
 148,536
 501,738
 431,856
Electric generation fuel66,584
 70,503
 152,057
 165,627
93,642
 71,004
 208,442
 143,177
Residential exchange(14,246) (15,577) (52,814) (49,093)(15,295) (15,401) (56,430) (55,436)
Purchased natural gas32,224
 34,041
 248,208
 205,418
27,778
 30,192
 168,281
 211,679
Unrealized (gain) loss on derivative instruments, net(23) 6,327
 23,098
 (57,218)14,716
 (14,046) 29,861
 (21,953)
Utility operations and maintenance141,003
 138,265
 438,622
 422,273
142,857
 139,361
 450,236
 440,016
Non-utility expense and other9,994
 8,620
 27,857
 26,474
11,869
 10,518
 34,924
 31,132
Depreciation and amortization120,829
 110,022
 355,538
 328,809
138,253
 149,730
 483,623
 486,300
Conservation amortization25,395
 21,800
 85,847
 77,551
17,734
 21,601
 71,049
 82,489
Taxes other than income taxes66,367
 65,268
 262,099
 235,431
61,697
 63,822
 240,392
 248,357
Total operating expenses564,008
 534,118
 1,965,775
 1,711,568
600,286
 605,317
 2,132,116
 1,997,617
Operating income (loss)96,369
 84,476
 491,601
 537,892
26,721
 46,147
 280,660
 363,707
Other income (expense): 
  
     
  
    
Other income6,778
 6,131
 18,861
 19,184
12,373
 13,596
 35,334
 29,352
Other expense(2,878) (5,025) (6,134) (8,488)(2,023) (3,250) (5,624) (7,678)
Interest charges: 
  
     
  
    
AFUDC3,123
 2,702
 7,853
 7,663
3,732
 3,911
 10,652
 10,112
Interest expense(59,868) (60,914) (180,320) (182,336)(61,145) (58,278) (181,230) (174,853)
Income (loss) before income taxes43,524
 27,370
 331,861
 373,915
(20,342) 2,126
 139,792
 220,640
Income tax (benefit) expense14,424
 8,393
 109,015
 117,533
(5,085) (1,765) 16,072
 26,931
Net income (loss)$29,100
 $18,977
 $222,846
 $256,382
$(15,257) $3,891
 $123,720
 $193,709


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

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


Three Months Ended September 30, Nine Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162019 2018 2019 2018
Net income (loss)$29,100
 $18,977
 $222,846
 $256,382
$(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 $939, $1,422, $3,813 and $3,942, respectively1,744
 2,642
 7,083
 7,322
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $128 and $128, respectively79
 79
 237
 237
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)1,823
 2,721
 7,320
 7,559
1,437
 (17) 6,651
 (21,431)
Comprehensive income (loss)$30,923
 $21,698
 $230,166
 $263,941
$(13,820) $3,874
 $130,371
 $172,278

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

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



ASSETS
September 30,
2017		 December 31,
2016		September 30,
2019		 December 31,
2018
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):   
Utility plant (at original cost, including construction work in progress of $658,261 and $550,466, respectively):   
Electric plant$10,036,204
 $9,813,169
$10,797,117
 $10,587,231
Natural gas plant3,838,533
 3,640,271
4,386,972
 4,164,489
Common plant776,116
 632,718
1,109,251
 1,052,544
Less: Accumulated depreciation and amortization(5,149,098) (4,927,602)(5,804,733) (5,495,348)
Net utility plant9,501,755
 9,158,556
10,488,607
 10,308,916
Other property and investments: 
  
 
  
Other property and investments78,332
 77,960
81,013
 76,986
Total other property and investments78,332
 77,960
81,013
 76,986
Current assets: 
  
 
  
Cash and cash equivalents5,939
 28,481
10,929
 35,452
Restricted cash9,302
 12,418
27,659
 18,041
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively237,091
 344,964
Accounts receivable, net of allowance for doubtful accounts of $7,608 and $8,408, respectively209,586
 346,251
Unbilled revenue126,252
 234,053
145,073
 205,285
Purchased gas adjustment receivable—
 2,785
155,711
 9,921
Materials and supplies, at average cost108,814
 106,378
120,143
 116,180
Fuel and natural gas inventory, at average cost59,640
 56,851
60,470
 52,028
Unrealized gain on derivative instruments16,605
 54,341
14,147
 46,507
Prepaid expense and other35,655
 43,046
28,502
 25,674
Total current assets599,298
 883,317
772,220
 855,339
Other long-term and regulatory assets: 
  
 
  
Regulatory asset for deferred income taxes71,057
 71,517
Power cost adjustment mechanism4,540
 4,531
24,810
 4,735
Other regulatory assets1,014,804
 1,034,352
717,596
 773,552
Unrealized gain on derivative instruments2,877
 8,738
2,294
 2,512
Operating lease right of use asset168,491
 —
Other65,138
 58,109
84,651
 75,483
Total other long-term and regulatory assets1,158,416
 1,177,247
997,842
 856,282
Total assets$11,337,801
 $11,297,080
$12,339,682
 $12,097,523

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

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


CAPITALIZATION AND LIABILITIES

September 30,
2017		 December 31,
2016		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
$859
 $859
Additional paid-in capital3,275,105
 3,275,105
3,485,105
 3,275,105
Retained earnings486,095
 359,795
632,702
 622,844
Accumulated other comprehensive income (loss), net of tax(138,191) (145,511)(184,233) (190,884)
Total common shareholder’s equity3,623,868
 3,490,248
3,934,433
 3,707,924
Long-term debt: 
  
 
  
First mortgage bonds and senior notes3,164,412
 3,362,000
4,212,000
 3,764,417
Pollution control bonds161,860
 161,860
161,860
 161,860
Junior subordinated notes250,000
 250,000
Debt discount, issuance costs and other(27,043) (28,974)(38,067) (31,417)
Total long-term debt3,549,229
 3,744,886
4,335,793
 3,894,860
Total capitalization7,173,097
 7,235,134
8,270,226
 7,602,784
Current liabilities: 
  
 
  
Accounts payable296,659
 317,043
288,194
 480,195
Short-term debt139,000
 245,763
69,000
 379,297
Current maturities of long-term debt200,000
 2,412
2,412
 —
Purchased gas adjustment payable5,784
 —
Accrued expenses: 
  
 
  
Taxes81,354
 111,428
77,815
 117,993
Salaries and wages41,121
 49,749
43,488
 50,785
Interest56,254
 48,087
58,410
 43,951
Unrealized loss on derivative instruments49,820
 44,170
30,504
 46,661
Operating lease liabilities15,173
 —
Other81,486
 71,996
104,132
 79,312
Total current liabilities951,478
 890,648
689,128
 1,198,194
Other long-term and regulatory liabilities: 
  
 
  
Deferred income taxes1,844,886
 1,732,390
949,526
 926,403
Unrealized loss on derivative instruments15,578
 16,261
18,222
 11,095
Regulatory liabilities610,902
 653,296
709,249
 745,880
Regulatory liability for deferred income taxes953,627
 976,582
Operating lease liabilities159,913
 —
Other deferred credits741,860
 769,351
589,791
 636,585
Total other long-term and regulatory liabilities3,213,226
 3,171,298
3,380,328
 3,296,545
Commitments and contingencies (Note 8)

 



 

Total capitalization and liabilities$11,337,801
 $11,297,080
$12,339,682
 $12,097,523

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

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

 Common Stock Additional   Accumulated Other  
 Shares Amount 
Paid-in
Capital
 Retained Earnings 
Comprehensive
Income (loss)
 
Total
Equity
Balance at December 31, 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.



PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended
September 30,		Nine Months Ended September 30,
2017 20162019 2018
Operating activities:      
Net income (loss)$222,846
 $256,382
$123,720
 $193,709
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
   
  
Depreciation and amortization355,538
 328,809
483,623
 486,300
Conservation amortization85,847
 77,551
71,049
 82,489
Deferred income taxes and tax credits, net109,015
 116,982
(1,600) 12,801
Net unrealized (gain) loss on derivative instruments23,098
 (57,218)29,861
 (21,953)
AFUDC – equity(11,266) (10,769)(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) (24,000)(18,000) (13,500)
Regulatory assets and liabilities(83,370) (138,096)(46,993) (22,545)
Other long-term assets and liabilities(15,734) 34,128
4,972
 5,144
Change in certain current assets and liabilities: 
   
  
Accounts receivable and unbilled revenue215,674
 175,733
196,877
 208,359
Materials and supplies(2,436) (28,448)(3,963) (7,002)
Fuel and natural gas inventory(2,789) (3,222)(8,442) (7,385)
Prepayments and other7,391
 (29,352)(2,283) (15,763)
Purchased gas adjustment8,569
 (10,743)(145,790) 19,911
Accounts payable(31,027) (22,874)(160,850) (37,988)
Taxes payable(30,074) (36,411)(40,178) 7,580
Other(857) 22,035
794
 (9,528)
Net cash provided by (used in) operating activities832,425
 650,487
431,089
 814,813
Investing activities: 
  
 
  
Construction expenditures – excluding equity AFUDC(677,004) (507,703)(680,118) (712,329)
Restricted cash3,116
 (1,391)
Other6,233
 2,519
(5,916) 2,090
Net cash provided by (used in) investing activities(667,655) (506,575)(686,034) (710,239)
Financing activities: 
  
 
  
Change in short-term debt, net(106,763) 12,996
(310,297) (123,463)
Dividends paid(96,546) (195,865)(113,862) (151,315)
Long-term bonds and notes issued443,151
 594,750
Redemption of bonds and notes—
 (450,000)
Investment from parent210,000
 —
Other15,997
 13,510
11,048
 6,228
Net cash provided by (used in) financing activities(187,312) (169,359)240,040
 (123,800)
Net increase (decrease) in cash and cash equivalents(22,542) (25,447)
Cash and cash equivalents at beginning of period28,481
 41,856
Cash and cash equivalents at end of period$5,939
 $16,409
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)$160,426
 $162,091
$152,571
 $152,273
Cash payments (refunds) for income taxes3,058
 —
$16,540
 $13,839
Non-cash financing and investing activities:      
Accounts payable for capital expenditures eliminated from cash flows$87,456
 $58,278
$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.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)


(1)Summary of Consolidation and Significant Accounting Policy

Basis of Presentation
Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE).  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC, (Puget LNG). Puget LNG was formed on November 29, 2016, andwhich has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur underare incurred by PSE and are allocated to Puget LNG are related party transactions by nature. As of September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.
In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC)FASB ASC 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”Company”.  The consolidated financial statementsinformation furnished herein reflects all adjustments which are, presented after eliminationin the opinion of allmanagement, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All significant intercompany itemsaccounts and transactions.transactions are eliminated in consolidation.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments.  The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP)GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.

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 willis intended to provide peak-shaving services to PSE’s natural gas customers, andcustomers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide LNG as fuel to transportation customers, particularly in the marine market. The TacomaOn January 24, 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) is 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. PSE received the SEIS which concluded the LNG facility is expected towould result in a net decrease in GHG emissions, provided in part that the natural gas for the facility was sourced from British Columbia or Alberta. PSE must now await the final determination by PSCAA.
If delayed, the construction schedule and costs may be operational in 2019.adversely impacted. Pursuant to an order by the Washington Commission’s order, Puget LNGCommission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of thecommon capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0%to Puget LNG. Per this allocation of the capital and operating costs.
For Puget Energy, $86.4costs, $191.8 million inof construction work in progress and $1.0 million of operating costs related to Puget LNG’sLNG's portion of the Tacoma LNG facility isare reported in the “OtherPuget Energy "Other property and investments”investments" and "Non-utility expense and other" financial statement line item. For PSE,items, respectively, as of September 30, 2019. Additionally, $156.1 million of construction work in progress of $76.3 million related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item, as 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

Revenue Recognition
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". ASU 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. TheRecently Adopted Accounting Standards Update (ASU) is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.
In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date", deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to early adopt ASU 2014-09 using the original effective date.

The Company will adopt ASU 2014-09 during the first quarter of fiscal year 2018 by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of retained earnings, effective January 1, 2018. In preparation for adoption of the standard, the Company has evaluated key accounting assessments related to the standard. As of the date of this report, the Company has not identified material differences in revenue recognition between current GAAP and ASU 2014-09 and as a result, the Company has not identified material cumulative adjustments necessary. The Company's primary revenue sources are from rate-regulated sales of electricity and natural gas to retail customers where revenue is recognized over time as delivered. The Company will include a change in the presentation of alternative revenue program revenue of the Company's consolidated statement of income as well as expanded disclosure around the disaggregation of revenue.

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 right-of-use (ROU)ROU lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amendingamended the FASB Accounting Standards CodificationASC and creatingcreated Topic 842, Leases. ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-useROU asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.
This amendment isIn 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. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company will adopthas adopted ASU 2016-02 duringas of January 1, 2019, which resulted in the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assetsROU asset and liabilitieslease liability financial statement line items that have not previously been recorded which willand 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 balance sheets. The Company is considering whether the new guidance will affect the accounting for purchase power agreements, easements and rights–of–way, utility pole attachments, and other utility industry–related arrangements.financial statements included in Item 1 of this report.

Statement of Cash Flows
Internal-Use Software
In August 2016,2018, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments2018-15, "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 ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle.
Thisthis update isare effective for financial statements issuedpublic business entities for fiscal years beginning after December 15, 2017,2019, 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 upon issuance.entities. The amendments in this update should be applied using a retrospective transition methodeither retrospectively or prospectively to each period presented.all implementation costs incurred after the date of adoption. The Company will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.
In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments inadopted this update require that a statementprospectively in 2019 for implementation costs incurred in hosting arrangements and application of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented and doesamendment has not anticipate the new guidance will havehad a material impact on the consolidated statement of cash flows.

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

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

Retirement BenefitsAccounting Standards Issued but Not Yet Adopted
Credit Losses
In March 2017,June 2016, the FASB issued ASU 2017-07,2016-13, "CompensationFinancial Instruments - Retirement BenefitsCredit Losses (Topic 715)326): ImprovingMeasurement of Credit Losses on Financial Instruments". The amendments in the Presentationupdate change how entities account for credit losses on receivables and certain other assets. The guidance requires use of Net Periodic Pension Costa 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 Net Periodic Postretirement Benefit Costannual periods beginning on or after December 15, 2019. The Company is currently evaluating the impact of adoption of the new standard on its consolidated financial statements.

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 require that an employer reportin this update modify the service cost componentdisclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the same line items as other compensationConcepts Statement, including the consideration of costs arising from services rendered by the pertinent employees during the period.and benefits. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or creditsamendments are effective for fiscal years, and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.
This amendment is effective forinterim periods within those fiscal years, beginning after December 15, 2017, including interim periods within those years.2019. The Company is in the process of evaluating potential impacts of these amendments to Note 5, "Fair Value Measurements", to the consolidated financial statements.

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. The Company is in the process of evaluating potential impacts of these amendments to Note 6, "Retirement Benefits", to the consolidated financial statements.


(3) Revenue

The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:
Puget Energy and
Puget Sound Energy
       
(Dollars in Thousands)Three Months Ended
September 30,		 Nine Months Ended
September 30,
Revenue from contracts with customers:2019 2018 2019 2018
Electric retail$450,109
 $464,210
 $1,550,517
 $1,563,394
Natural gas retail101,395
 101,995
 569,177
 594,572
Other72,691
 67,217
 245,285
 148,581
Total revenue from contracts with customers624,195
 633,422
 2,364,979
 2,306,547
Alternative revenue programs874
 (782) (20,006) (24,678)
Other non-customer revenue1,938
 18,824
 67,803
 79,455
Total operating revenue$627,007
 $651,464
 $2,412,776
 $2,361,324

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 services and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

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

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

Biogas 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 beginningestablished 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 annual period for which financial statements (interim or annual) haveagent within the market that connects a seller to a purchaser.

Other Revenue
In accordance with ASC 606, PSE separately presents revenue not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018. For the periods presented in the income statement, the Company’s non-service components for the nine months ended September 30, 2017, was a credit of $13.8 million for Puget Energy and $3.5 million for PSE.  The non-service cost components are in an income position and will be presented in thecollected from contracts with customers that falls under other income section, upon adoption.accounting guidance.


(3)(4) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). 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. As of September 30, 2017, the Company did not have any outstanding interest rate swap instruments.


The following table presents the volumes, fair values and locationsclassification of the Company's derivative instruments recorded on the balance sheets:
Puget Energy and
Puget Sound Energy
                 
At September 30, 2017 At December 31, 2016At September 30, 2019 December 31, 2018
(Dollars in Thousands)Volumes 
Assets1
 
Liabilities2
 Volumes 
Assets1
 
Liabilities2
Volumes 
Assets1
 
Liabilities2
 Volumes 
Assets1
 
Liabilities2
Interest rate swap derivatives3
$—
 $—
 $—
 $450 million $—
 $141
Electric portfolio derivatives* 11,656
 39,622
 * 36,460
 41,329
* $9,483
 $33,341
 * $33,287
 $27,284
Natural gas derivatives (MMBtus)4
305.3 million 7,826
 25,776
 336.4 million 26,619
 19,101
Natural gas derivatives (MMBtus)3
288.3 million 6,958
 15,385
 336.6 million 15,732
 30,472
Total derivative contracts** $19,482
 $65,398
 ** $63,079
 $60,571
  $16,441
 $48,726
   $49,019
 $57,756
Current** $16,605
 $49,820
 ** $54,341
 $44,310
  $14,147
 $30,504
 $46,507
 $46,661
Long-term** 2,877
 15,578
 ** 8,738
 16,261
 2,294
 18,222
 2,512
 11,095
Total derivative contracts** $19,482
 $65,398
 ** $63,079
 $60,571
 $16,441
 $48,726
 $49,019
 $57,756
_______________
1 
Balance sheet locations:classification: Current and Long-term Unrealized gain on derivative instruments.
2 
Balance sheet locations:classification: Current and Long-term Unrealized loss on derivative instruments.
3
Interest rate swap contracts are only held at Puget Energy, and matured January 2017.
4 
All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
* 
Electric portfolio derivatives consist of electric generation fuel of 165.0183.6 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.611.9 million Megawatt Hours (MWhs) at September 30, 2017,2019, and 186.8194.8 million MMBtus and 3.66.6 million MWhs at December 31, 2016.
**Not meaningful and/or applicable.2018.

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

statements included in Item 1 of this report.
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
Puget Energy and
Puget Sound Energy
      
Puget Energy and
Puget Sound Energy
        
At September 30, 2017At 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  
Gross Amount Recognized in the Statement of Financial Position1
 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position  

(Dollars in Thousands)
 Commodity ContractsCash Collateral Received/Posted Net Amount Commodity Contracts Cash Collateral Received/Posted Net Amount
Assets:                    
Energy derivative contracts$19,482
 $—
 $19,482
 $(12,961)$—
 $6,521
$16,441
 $—
 $16,441
 $(14,148) $—
 $2,293
Liabilities:                    
Energy derivative contracts65,398
 —
 65,398
 (12,961)(739) 51,698
48,726
 —
 48,726
 (14,148) (5,379) 29,199


        
Puget Energy and
Puget Sound Energy
Puget Energy and
Puget Sound Energy
      At December 31, 2018
At December 31, 2016
Gross Amount Recognized in the Statement of Financial Position1
 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position  
Gross Amount Recognized in the Statement of Financial Position1
 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position  

(Dollars in Thousands)
 Commodity ContractsCash Collateral Received/Posted Net Amount Commodity Contracts Cash Collateral Received/Posted Net Amount
Assets:                    
Energy derivative contracts$63,079
 $—
 $63,079
 $(42,858)$—
 $20,221
$49,019
 $—
 $49,019
 $(25,388) $—
 $23,631
Liabilities:                    
Energy derivative contracts60,430
 —
 60,430
 (42,858)—
 17,572
57,756
 —
 57,756
 (25,388) —
 32,368
Interest rate swaps2
141
 —
 141
 —
—
 141
_______________
1 
All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
2
Interest rate swap contracts are only held at Puget Energy, and matured January 2017.




The following table presents the effect and locationsclassification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:
Puget Energy and
Puget Sound Energy		 Three Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)Location2017 2016 2017 2016
Interest rate contracts1:
        
 
Non-hedged interest rate swap
(expense) income
$—
 $563
 $28
 $(651)
 Interest expense—
 (349) —
 (349)
Gas for Power Derivatives:    
    
UnrealizedUnrealized gain (loss) on derivative instruments, net903
 (8,873) (20,979) 41,957
RealizedElectric generation fuel(6,753) (3,194) (14,773) (36,204)
Power Derivatives:        
UnrealizedUnrealized gain (loss) on derivative instruments, net(880) 2,546
 (2,119) 15,261
RealizedPurchased electricity(4,356) (1,282) (14,434) (16,077)
Total gain (loss) recognized in income on derivatives $(11,086) $(10,589) $(52,277) $3,937
_______________
1Interest rate swap contracts are only held at Puget Energy, and matured January 2017.
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, 2017,2019, approximately 98.5%97.8% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, wasis with counterparties that are rated at least investment grade by rating agencies and 1.5%2.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of September 30, 2017, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transactingalso transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2017,2019, PSE had cash posted as collateral of $1.4$17.1 million related to contracts executed on thisthe ICE platform. As additional contracts are executed on this exchange, the amountAlso, as of collateral to be posted will increase, subject to PSE’s established limit.September 30, 2019, PSE also hashad $1.0 million in a$1.0 million letter of credit posted as

collateral as a condition of transacting on a physical energy exchange and clearing house in Canada.the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties during the nine months ended September 30, 2017 nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.downgrades during the nine months ended September 30, 2019.

The following table below presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the overall contractual contingent liability positions foramount of additional collateral the Company's derivative activity at September 30, 2017:Company could be required to post:
Puget Energy and
Puget Sound Energy
                      
(Dollars in Thousands)At September 30, 2017 At December 31, 2016At September 30, 2019 At December 31, 2018
Fair Value1
 Posted Contingent 
Fair Value1
 Posted Contingent
Fair Value1
 Posted Contingent 
Fair Value1
 Posted Contingent
Contingent FeatureLiability Collateral Collateral Liability Collateral CollateralLiability Collateral Collateral Liability Collateral Collateral
Credit rating2
$6,113
 $—
 $6,113
 $4,894
 $—
 $4,894
$12,147
 $—
 $12,147
 $574
 $—
 $574
Requested credit for adequate assurance27,214
 —
 —
 7,427
 —
 —
5,447
 —
 —
 18,495
 —
 —
Forward value of contract3
739
 1,384
 —
 507
 —
 —
5,379
 17,117
 —
 —
 —
 —
Total$34,066
 $1,384
 $6,113
 $12,828
 $—
 $4,894
$22,973
 $17,117
 $12,147
 $19,069
 $—
 $574
_______________
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.


(4)(5)Fair Value Measurements

ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

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

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

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

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

basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service.
The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value
The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short termshort-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $49.4$51.1 million and $49.1$49.5 million at September 30, 20172019 and December 31, 2016,2018, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.
The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:
Puget Energy At September 30, 2017 At December 31, 2016 At September 30, 2019 At December 31, 2018
(Dollars in Thousands)Level
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Level
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Liabilities:                
Junior subordinated notes2$250,000
 $246,232
 $250,000
 $210,261
Long-term debt (fixed-rate), net of discount1
25,101,936
 6,439,413
 5,091,593
 6,337,287
2$5,961,667
 $7,544,799
 $5,510,591
 $6,443,742
Long-term debt (variable-rate)283,064
 83,064
 12,480
 12,480
2400,900
 400,900
 161,900
 161,900
Total liabilities $5,435,000
 $6,768,709
 $5,354,073
 $6,560,028
 $6,362,567
 $7,945,699
 $5,672,491
 $6,605,642

Puget Sound Energy At September 30, 2017 At December 31, 2016 At September 30, 2019 At December 31, 2018
(Dollars in Thousands)LevelCarrying
Value		 Fair
Value		 Carrying
Value		 Fair
Value		LevelCarrying
Value		 Fair
Value		 Carrying
Value		 Fair
Value
Liabilities:                
Junior subordinated notes2$250,000
 $246,232
 $250,000
 $210,261
Long-term debt (fixed-rate), net of discount2
23,499,229
 4,465,126
 3,497,298
 4,360,783
2$4,338,205
 $5,642,813
 $3,894,860
 $4,574,611
Total liabilities $3,749,229
 $4,711,358
 $3,747,298
 $4,571,044
 $4,338,205
 $5,642,813
 $3,894,860
 $4,574,611
_______________
1 
The carrying value includes debt issuances costs of $29.1$24.8 million and $33.0$26.1 million for September 30, 20172019 and December 31, 2016,2018, respectively, which are not included in fair value.
2 
The carrying value includes debt issuances costs of $25.3$24.6 million and $27.2$24.6 million for September 30, 20172019 and December 31, 2016,2018, 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 andFair Value Fair Value
Puget Sound EnergyAt September 30, 2017 At December 31, 2016
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 TotalLevel 2 Level 3 Total Level 2 Level 3 Total
Assets:                      
Electric derivative instruments$7,106
 $4,550
 $11,656
 $30,666
 $5,794
 $36,460
$8,612
 $871
 $9,483
 $28,765
 $4,522
 $33,287
Natural gas derivative instruments3,794
 4,032
 7,826
 23,316
 3,303
 26,619
5,279
 1,679
 6,958
 12,247
 3,485
 15,732
Total assets$10,900
 $8,582
 $19,482
 $53,982
 $9,097
 $63,079
$13,891
 $2,550
 $16,441
 $41,012
 $8,007
 $49,019
Liabilities: 
  
  
  
  
  
 
  
  
  
  
  
Interest rate derivative instruments1
$—
 $—
 $—
 $141
 $—
 $141
Electric derivative instruments36,482
 3,140
 39,622
 36,507
 4,822
 41,329
$27,942
 $5,399
 $33,341
 $24,124
 $3,160
 $27,284
Natural gas derivative instruments23,998
 1,778
 25,776
 16,423
 2,678
 19,101
15,143
 242
 15,385
 28,660
 1,812
 30,472
Total liabilities$60,480
 $4,918
 $65,398
 $53,071
 $7,500
 $60,571
$43,085
 $5,641
 $48,726
 $52,784
 $4,972
 $57,756
_______________
1
Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
Puget Energy and
Puget Sound Energy
Three Months Ended September 30,Three Months Ended
September 30,
(Dollars in Thousands)2017 20162019 2018
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas TotalElectric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period$643
 $1,456
 $2,099
 $(3,062) $(484) $(3,546)$(2,446) $2,398
 $(48) $2,009
 $3,949
 $5,958
Changes during period:                      
Realized and unrealized energy derivatives:                      
Included in earnings1
2,458
 —
 2,458
 574
 —
 574
(4,611) —
 (4,611) 67
 —
 67
Included in regulatory assets / liabilities—
 2,133
 2,133
 —
 (212) (212)—
 206
 206
 —
 930
 930
Settlements(1,783) (1,301) (3,084) 93
 84
 177
2,529
 (1,167) 1,362
 (945) (2,217) (3,162)
Transferred into Level 3(1,668) —
 (1,668) (727) —
 (727)—
 —
 —
 (150) —
 (150)
Transferred out of Level 31,760
 (34) 1,726
 2,532
 (331) 2,201
—
 —
 —
 396
 514
 910
Balance at end of period$1,410
 $2,254
 $3,664
 $(590) $(943) $(1,533)$(4,528) $1,437
 $(3,091) $1,377
 $3,176
 $4,553
______________

Puget Energy and
Puget Sound Energy
Nine 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$1,362
 $1,673
 $3,035
 $1,098
 $1,923
 $3,021
Changes during period:           
Realized and unrealized energy derivatives:           
Included in earnings2
1,524
 —
 1,524
 2,052
 —
 2,052
Included in regulatory assets / liabilities—
 2,485
 2,485
 —
 6,260
 6,260
Settlements(10,380) (3,885) (14,265) (1,599) (5,819) (7,418)
Transferred into Level 34,390
 (400) 3,990
 (1,987) —
 (1,987)
Transferred out of Level 3(1,424) 1,564
 140
 1,813
 812
 2,625
Balance at end of period$(4,528) $1,437
 $(3,091) $1,377
 $3,176
 $4,553
_______________
11. 
Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.9$(4.5) million and $(0.1) million for the three months ended September 30, 20172019 and 20162018., respectively.

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
Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016
Level 3 Roll-Forward Net Asset/(Liability)Electric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period$972
 $625
 $1,597
 $(7,345) $(2,383) $(9,728)
Changes during period:           
Realized and unrealized energy derivatives:           
Included in earnings1
3,503
 —
 3,503
 3,228
 —
 3,228
Included in regulatory assets / liabilities—
 5,715
 5,715
 —
 2,869
 2,869
Settlements(5,622) (4,605) (10,227) (461) (1,731) (2,192)
Transferred into Level 3523
 (553) (30) (2,807) —
 (2,807)
Transferred out of Level 32,034
 1,072
 3,106
 6,795
 302
 7,097
Balance at end of period$1,410
 $2,254
 $3,664
 $(590) $(943) $(1,533)
______________
12. 
Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.9$(4.4) millionand $4.0$1.4 million for the nine months ended September 30, 20172019 and 2016,2018, 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 following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 20172019:
Puget Energy and
Puget Sound Energy		Fair Value Range  Fair Value Range  
(Dollars in Thousands)
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Electric$4,550
 $3,140
 Discounted cash flow Power prices (per MWh) $8.54
 $28.98
 $17.99
$871
 $5,399
 Discounted cash flow Power prices (per MWh) $6.35
 $40.04
 $31.32
Natural gas$4,032
 $1,778
 Discounted cash flow Natural gas prices (per MMBtu) $0.38
 $3.09
 $2.75
$1,679
 $242
 Discounted cash flow Natural gas prices (per MMBtu) $1.84
 $2.48
 $2.11
_______________
1 
The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.


The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2016:2018:
Puget Energy and
Puget Sound Energy		Fair Value Range  Fair Value Range  
(Dollars in Thousands)
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Assets1
 
Liabilities1
 Valuation Technique Unobservable Input Low High Weighted Average
Electric$5,794
 $4,822
 Discounted cash flow Power prices (per MWh) $11.86
 $33.52
 $27.61
$4,522
 $3,160
 Discounted cash flow Power prices (per MWh) $11.35
 $66.45
 $29.63
Natural gas$3,303
 $2,678
 Discounted cash flow Natural gas prices (per MMBtu) $2.00
 $3.24
 $2.42
$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.

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. AtAs of September 30, 20172019 and December 31, 2016,2018, a hypothetical 10%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 $1.7$1.9 million and $0.2$2.6 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of anyrecoverability whenever events or changes in circumstances indicate that wouldits carrying amount may not be more likely than not to reduce the fair value of the long-lived assets below their carrying value.recoverable. One such triggering event is a significant decrease in the forward market prices of power.
As of September 30, 2017,2019, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 3.5% from June 30, 2017, causing an impairment of $1.0 million. As of March 31, 2017, due to significant decreases in forward power prices of 14.1% for years 2017-2022,assets and 24.4% for years 2023-2035 from December 31, 2016, impairments totaling $80.3 million were recorded to the Company's intangible asset contracts.

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


found no impairment. The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.
The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value:
Puget Energy      
Valuation DateUnobservable InputLow High Average
September 30, 2017      
Wells HydroPower prices (per MWh)$14.06 $26.86 $22.24
 Power contract costs per quarter (in thousands)4,126 4,126 4,126
       
March 31, 2017      
Wells HydroPower prices (per MWh)$8.76 $26.70 $20.86
 Power contract costs per quarter (in thousands)3,965 4,223 4,051
Rocky ReachPower prices (per MWh)$8.53 $48.21 $27.69
 Power contract costs per quarter (in thousands)5,827 6,780 6,150
Priest Rapids RPPower prices (per MWh)$13.70 $29.38 $23.14
 Power contract costs per year (in thousands)620 4,022 2,306


(5)(6)Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portiona substantial majority of PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  Starting January 1, 2014, all non-represented and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees, along with International Brotherhood of Electrical Workers (IBEW) represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount.   PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for itscertain key senior management employees.
Officers hired after January 2019 participate in an Officer Restoration Benefit as part of the Deferred Compensation Plan for Key Employees. In addition to providing pension benefits, PSE provides access tolegacy group medicalhealth care coverage and legacy life insurance benefits (Other Benefits) for certain retired employees.  These benefits are provided principally through an insurance company.  The group medical insurance premiums, paid primarily by retirees, are based onPuget Energy's retirement plans were re-measured as a result of the benefits provided duringmerger in 2009, which represents the prior year.
difference between Puget Energy records purchase accounting adjustments associated with the re-measurement of theand PSE's retirement plans.

The following tables summarize the Company’s net periodic benefit cost for the three months and nine months ended September 30, 20172019 and 2016:2018:
Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits		Qualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
Three Months Ended September 30,Three Months Ended September 30,
(Dollars in Thousands)2017 2016 2017 2016 2017 20162019 2018 2019 2018 2019 2018
Components of net periodic benefit cost:                      
Service cost$5,020
 $4,976
 $228
 $271
 $18
 $21
$6,418
 $6,218
 $256
 $212
 $13
 $17
Interest cost7,093
 7,064
 571
 581
 125
 88
7,252
 6,917
 578
 530
 84
 113
Expected return on plan assets(11,945) (11,589) —
 —
 (115) (112)(12,439) (12,533) —
 —
 (100) (119)
Amortization of prior service cost(495) (495) 11
 11
 —
 —
(495) (495) 83
 11
 —
 —
Amortization of net loss (gain)—
 —
 269
 228
 (101) (233)362
 716
 341
 394
 (156) (80)
Net periodic benefit cost$(327) $(44) $1,079
 $1,091
 $(73) $(236)$1,098
 $823
 $1,258
 $1,147
 $(159) $(69)

Puget EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits		Qualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
Nine Months Ended
September 30,		Nine Months Ended September 30,
(Dollars in Thousands)2017 2016 2017 2016 2017 20162019 2018 2019 2018 2019 2018
Components of net periodic benefit cost:                      
Service cost$15,060
 $14,185
 $685
 $814
 $54
 $70
$16,992
 $17,068
 $768
 $635
 $46
 $52
Interest cost21,279
 21,516
 1,714
 1,744
 375
 399
21,685
 20,477
 1,735
 1,590
 308
 333
Expected return on plan assets(35,837) (34,964) —
 —
 (346) (334)(37,686) (37,652) —
 —
 (295) (354)
Amortization of prior service cost(1,485) (1,485) 33
 32
 —
 —
(1,485) (1,485) 249
 33
 —
 —
Amortization of net loss (gain)—
 —
 807
 683
 (302) (289)863
 1,640
 1,024
 1,185
 (281) (252)
Net periodic benefit cost$(983) $(748) $3,239
 $3,273
 $(219) $(154)$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)2017 2016 2017 2016 2017 2016
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$5,020
 $4,976
 $228
 $271
 $18
 $21
 Interest cost7,093
 7,064
 571
 581
 125
 88
 Expected return on plan assets(11,965) (11,638) —
 —
 (115) (112)
 Amortization of prior service cost(393) (393) 11
 11
 —
 —
 Amortization of net loss (gain)3,262
 3,963
 392
 333
 (160) (295)
 Net periodic benefit cost$3,017
 $3,972
 $1,202
 $1,196
 $(132) $(298)
 Puget Sound 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 EnergyQualified
Pension Benefits		 SERP
Pension Benefits		 Other
Benefits
 
  Nine Months Ended
September 30,
 (Dollars in Thousands)2017 2016 2017 2016 2017 2016
 Components of net periodic benefit cost: 
  
  
  
  
  
 Service cost$15,060
 $14,185
 $685
 $814
 $54
 $70
 Interest cost21,279
 21,516
 1,714
 1,744
 375
 399
 Expected return on plan assets(35,896) (35,110) —
 —
 (346) (334)
 Amortization of prior service cost(1,180) (1,180) 33
 33
 —
 —
 Amortization of net loss (gain)9,786
 11,443
 1,175
 997
 (480) (474)
 Net periodic benefit cost$9,049
 $10,854
 $3,607
 $3,588
 $(397) $(339)
 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, 20172019 and December 31, 2016:2018:
Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
Qualified
Pension Benefits
 
SERP
Pension Benefits
 
Other
Benefits
Nine Months Ended
 Year
Ended		 Nine Months Ended
 Year
Ended		 Nine Months Ended
 Year
Ended		Nine Months Ended Year
Ended		 Nine Months Ended Year
Ended		 Nine Months Ended Year
Ended
(Dollars in Thousands)September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016		 September 30,
2017		 December 31,
2016		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$652,607
 $643,088
 $51,734
 $51,279
 $11,194
 $13,946
$677,643
 $700,481
 $55,708
 $55,754
 $10,636
 $11,454
Amendments—
 —
 —
 1,446
 —
 —
Service cost15,060
 18,913
 685
 1,085
 54
 93
16,992
 22,757
 768
 847
 46
 69
Interest cost21,279
 28,689
 1,714
 2,325
 375
 533
21,685
 27,303
 1,735
 2,120
 308
 444
Actuarial loss (gain)(253) 1,545
 —
 106
 373
 (2,262)1,644
 (29,067) —
 1,122
 (909) (379)
Benefits paid(31,344) (38,730) (1,428) (3,061) (857) (1,264)(33,619) (42,662) (2,297) (5,581) (719) (1,037)
Medicare part D subsidy received—
 —
 —
 —
 100
 148
—
 —
 —
 —
 226
 85
Administrative Expense—
 (898) —
 —
 —
 —
—
 (1,169) —
 —
 —
 —
Benefit obligation at end of period$657,349
 $652,607
 $52,705
 $51,734
 $11,239
 $11,194
$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, 20172019 are expected to be at least $18.0 million, $1.9$6.2 million and $0.3 million, respectively. During the three months ended September 30, 2017,2019, the Company made no contributionscontributed $18.0 million and $1.3 million to fund the qualified pension plan as the aggregate funding for the year has already been reached for the year ending December 31, 2017. During the three months ended September 30, 2017, the Company contributed $0.5 million and $0.1 million to fund the SERP, and other postretirement plan, respectively. During the nine months ended September 30, 2017,2019, the Company contributed $18.0 million $1.4 million and $0.2$2.3 million to fund the qualified pension plan and SERP, andrespectively. The Company contributed an immaterial amount to fund the other postretirement plan, respectively.
plans.

(6)
(7) Regulation and Rates

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

order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the K-Factor (rate plan) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next general rate case (GRC) which was filed January 13, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.

General Rate Case Filing
On January 13, 2017, PSE filed its GRC with the Washington Commission which proposed a weighted coston June 20, 2019 requesting an overall increase in electric and natural gas rates of capital of 7.74%, or 6.69% after-tax,6.9% and a capital structure of 48.5% in common equity with7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. The requested combined electric tariff changes were a net increaseIn addition to the traditional areas of $86.3 million, or 4.1%focus (revenue requirements, cost allocation, rate design and cost of capital), annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates grantedCompany included an attrition adjustment mechanism to address the expected regulatory lag in the proceeding will go into effect no later than December 13, 2017.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, on April 3, 2017, which among other things provided updates to power costs. Theas discussed in our original filing, but did not impact the requested combinedoverall electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combinedand natural gas tariff changes basedrate increases, return on the updated supplemental filing would result in a net decreaseequity or overall rate of $29.3 million, or 3.2%, annually.return as originally filed.
PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
Expedited Rate Filing
On September 15, 2017, ten of the eleven parties, includingNovember 7, 2018, PSE filed a settlement agreementan ERF with the Washington Commission. The settlement agreement, if acceptedfiling 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 Commission, would resolveAdministrative 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 but fourparties 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 annual 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 contested issues betweenTCJA, using the settling parties. average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.
The settlement agreement provides for a weighted costthe pass back of capitalplant 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 7.6% or 6.55% after-tax,$6.1 million for natural gas and a capital structure$25.9 million for electric. The settlement agreement left the determination for the regulatory treatment of 48.5%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.
The agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in common equity with aits advanced metering infrastructure (AMI) investment and may defer the return on equitythe AMI investment that was included in the test year of 9.5%the filing. The agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s next 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 began May 1, 2019.

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 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 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 settlement also recommendsoverall impact of the rate change, based on the annual period from May 2018 through April 2019, is a combined electric tariff change that would result in a net increaserevenue decrease of $20.2$72.9 million, or 0.9%3.4% for electric and a combined$23.6 million, or 2.7% for natural gas tariffand 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 would result in a net decreaseencompasses

the effective date of $35.5 million, or 3.8%the TCJA through May 1, 2018, the effective date of the rate change). The contested issues are PSE’s proposed electric CRM,$34.6 million tax over-collection decreased PSE's revenue and increased the majorityregulatory liability for a refund to customers.
As a result of decoupling issues, certain portions of electric rate spread/rate design issuesthe Washington Commission’s final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the entire natural gas rate spread/rate design-related issues. Hearings were held on Augusttreatment 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 June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018 through April 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.2018, as discussed above, over a one-year period which began May 1, 2019.

Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigateassist in mitigating the impact of weather on operating revenue and net income. TheSince 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 will beare recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above.
Under the current mechanism, theThe revenue recorded under the decoupling mechanisms iswill be affected by customer growth and not actual consumption. One opposing party in PSE’s pending GRC is advocating that PSE's decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given testFollowing each calendar year, rather than to provide for the change in customers after the test year which PSE's existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms. PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to affectedApril 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 overwill 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 12-month period beginningGRC or ERF. Approved electric fixed production energy costs can also be changed in May followinga power cost only rate case (PCORC). Other changes to the calendar year end.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 end on December 31, 2017, unless the requested continuation of the mechanism is approvedbe reviewed again in PSE's 2017 GRC. PSE'sPSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism overover- and underunder- collections will still be collectible or refundable after December 31, 2017,this effective date even if the decoupling mechanism is not extended.

TheOn February 21, 2019, the Washington Commission approved the followingmulti-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, PSE requestsperformed an analysis to change rates under itsdetermine if electric and natural gas decoupling mechanisms:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Electric:   
May 1, 20172.0% $41.9
May 1, 20161.0 20.8
Natural Gas:   
May 1, 20172.4% $22.4
May 1, 20162.8 25.4
_______________
1
The increase in revenue is netrevenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and 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 reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.

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

Existing deferrals maydeferred revenue will be included in customer rates beginning in May 2018, subject to subsequent applicationcollected within 24 months of the earnings test and the 3.0% cap onannual period; therefore, no adjustment was booked to 2019 decoupling related rate increases.  revenue.

Electric Regulation and Rates
Storm Damage Deferral Accounting
The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary lossesstorm events and provided that costs in excess of $8.0 million annuallythe annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for a system average interruption duration index. For the nine months ended September 30, 2017 and 2016,2019, PSE incurred $21.1$39.3 million and $15.6 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4the Company deferred $28.5 million was deferred to a regulatory asset in 2017 and $6.5$0.4 million in 2016.

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

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

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

The settlement also resulted in the following changes to the PCA mechanism:
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets related to storms that occurred in 2019 and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);
Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
Establishment of a five-year moratorium on changes to the PCA.

For the nine months ended September 30, 2017, PSE under recovered its power costs by $8.9 million of which no amount was apportioned to customers.2018, respectively. This compares to an over recovery of power$8.9 million incurred in storm-related electric transmission and distribution system restoration costs of $1.4 million for the nine months ended September 30, 20162018, of which no amountsamount was deferred to a regulatory asset. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were apportionedapproved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease in$10.0 million effective January 1, 2018; and (ii) qualifying events where the total baseline ratequalifying cost is less than $0.5 million will not qualify for deferral and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixedthese costs will become part ofalso not count toward the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed$10.0 million annual cost portion of the baseline rate.threshold.

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

The following table sets forth conservation rider rate adjustments approved by the Washington Commission(8) Commitments and the corresponding expected annual impact on PSE’s revenue based on the effective dates:Contingencies
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 20170.7% $16.5
May 1, 2016(0.5) (11.7)

Electric Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes and true-ups to the rate from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2017(0.04)% $(0.9)
May 1, 20160.3 5.7

Federal Incentive Tracker Tariff
The federal incentive tracker tariff passes through to customers the benefits associated with realized treasury grants and production tax credits. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.
The following table sets forth the federal incentive tracker tariff revenue requirement proposed, as originally filed, by PSE and/or approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates from prior year
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2018, proposed0.2% $(48.2)
January 1, 20170.3 (51.7)
January 1, 2016(0.2) (57.3)

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

The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Total credit to be passed back to eligible customers
(Dollars in Millions)
October 1, 2017(0.6)% $(80.8)
October 1, 20152.4 (76.4)

Power Cost Update Compliance Filing
The power cost update compliance filing is an update to a limited-scope proceeding to periodically reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission’s Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC.
The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
December 1, 2016(1.7)% $(37.3)

Natural Gas Regulation and Rates
Natural Gas Conservation Rider
The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual versus forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
 Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
 
 
 
 May 1, 2017(0.1)% $(1.0)
 May 1, 20160.3 2.9

Natural Gas Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes.

The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2017(0.1)% $(1.1)
May 1, 20160.4 3.5

Natural Gas Cost Recovery Mechanism
The purpose of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system.
The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20170.5% $4.9
November 1, 20160.6 5.6

Purchased Gas Adjustment
PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, any natural gas supply and 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.
The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2017(3.3)% $(30.8)
November 1, 2016(0.4) (4.1)

(7)Asset Retirement Obligations

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, and natural gas mains where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).
On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments.
The CCR rule and two new agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations. The

changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.
On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional costs, such as, monitoring, water treatment, forced evaporation and post-closure care for all Colstrip Units. As a result, in 2016 the Company increased the Colstrip ARO ending liability by $45.7 million for Colstrip Units 1 and 2 and $37.0 million for Colstrip Units 3 and 4.
The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. The Company will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.
For the nine months ended September 30, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $1.5 million for PSE and $1.4 million for Puget LNG in September 2017.
The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017:
Puget Energy and
Puget Sound Energy

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


(8)Commitment and Contingencies

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. OnIn March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. OnIn July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court onin September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. 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 expects thathas accelerated the Washington Commission will allow full recovery in ratesdepreciation of Colstrip Units 3 and 4, per the terms of the net book value (NBV)GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.
On June 11, 2019, Talen made a public announcement that Colstrip 1 and 2 will be shut down at retirement and related decommissioning costs consistentthe end of the year due to operational losses associated with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to athe Units. The regulatory asset which represents the expected NBV atassociated with early retirement of Colstrip Units 1 and 2 based on the expected shutdown date of July 1, 2022increased from $130.7 million as of December 31, 2016. Due2018, to a re-estimate of Colstrip Units 1 and 2 ARO costs, the regulatory asset account was reduced to $175.0$178.2 million as of September 30, 2017. Colstrip Units 32019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and 4, which are newer and more efficient,remediation costs associated with the facilities that are not affected byrecovered through the settlement,repurposed PTC's and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the ARO for Colstrip Units 1 and 2, thehydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood
On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March

28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million, of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million, of which $1.3 million was suspended. On June 30, 2017, PSE paid the $1.5 million penalty it had accrued previously to a liability reserve account for property damage claims. However, litigation is still pending regarding damage and personal injury claims.

Other Commitments and Contingencies
The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company recorded reserves of $0.6 million and $0.7 million relating to these claims as of September 30, 2017 and December 31, 2016, respectively.
In additionThere have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in 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.

(9)  Leases

PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG 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 which include options to extend the leases for up to 25 years.
The components of lease expense were as follows:
Puget Energy and
Puget Sound Energy		Three Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2019 2019
Finance lease cost:   
Amortization of right-of-use asset$128
 $410
Interest on lease liabilities10
 29
Total finance lease cost$138
 $439
    
Operating lease cost1
$5,311
 $15,318
_______________
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.

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,
(Dollars in Thousands)2019 2019
Cash paid for amounts included in the measurement of lease liabilities:   
Operating cash flows for operating leases$(3,678) $(10,437)
Investing cash flow for operating leases1
(1,633) (4,881)
Operating cash flow for finance leases(10) (29)
Financing cash flows for finances leases(129) (410)
_______________
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.

Supplemental balance sheet information related to leases was as follows:
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, and December 31, 2018, respectively:
Maturities of lease liabilities
Future Minimum Lease Payments

(Dollars in Thousands)
At September 30,Operating Leases Finance Leases
2019 (remaining three months)$4,968
 $133
202021,514
 554
202121,791
 416
202221,375
 184
202320,935
 25
Thereafter135,492
 —
Total lease payments226,075
 1,312
Less imputed interest(50,989) (45)
Total$175,086
 $1,267

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 under 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.
    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 10-K10K for the year ended December 31, 2016, during the nine months ended September 30, 2017, the Company entered into new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.2018.



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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2016.2018. 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.

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). Puget LNG was formed on November 29, 2016, and, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNGliquefied natural gas (LNG) facility, 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 Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation and(BCIMC), the Alberta Investment Management Corporation.Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) 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.
Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended September 30, 2019 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
The principal business, economic and other factors that affect PSE's operations and financial performance include:
The rates PSE is allowed to charge for its services;
PSE’s ability to recover power costs that are included in rates which are based on volume;
Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, stream-flow and wind-speed which affect power generation, supply and price;
Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;
PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;return (ROR);
Availability and access to capital and the cost of capital;
Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
Wholesale commodity prices of electricity and natural gas;
Increasing capital expenditures with additional depreciation and amortization;
Bonus depreciationTax reform, the effect of lower tax rates, and the impactregulatory treatment of excess deferred tax balances on rate base;base and customer rates;
General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; and
Federal, state, and local taxes.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended September 30, 2017 is set forth below in this "Overview" section as well as in other sections of Management's Discussion and Analysis.

Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 20172019 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission).Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly, under existing modified historical ratemaking, the Company will need to seek rate relief through a rate case on a regular and frequent basis in the foreseeable future.future after the investment is made. 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 aan expense or 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, the Washington Commission also sets natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.

General Rate Case Filing
On January 13, 2017, PSE filed itsa general rate case (GRC) with the Washington Commission which proposed a weighted coston June 20, 2019 requesting an overall increase in electric and natural gas rates of capital of 7.74%, or 6.69% after-tax,6.9% and a capital structure of 48.5% in common equity with7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. The requested combined electric tariff changes were a net increaseIn addition to the traditional areas of $86.3 million, or 4.1%focus (revenue requirements, cost allocation, rate design and cost of capital), annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates grantedCompany included an attrition adjustment mechanism to address the expected regulatory lag in the proceeding will go into effect no later than December 13, 2017.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, on April 3, 2017, which among other things provided updates to power costs. Theas discussed in our original filing, but did not impact the requested combinedoverall electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combinedand natural gas tariff changes basedrate increases, return on the updated supplemental filing would result in a net decreaseequity or overall rate of $29.3 million, or 3.2%, annually.
PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. It also requested that electric energy supplyreturn as originally filed.

fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an
Expedited Rate Filing (ERF) that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.
On September 15, 2017, ten of the eleven parties, includingNovember 7, 2018, PSE filed a settlement agreementan ERF with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement if accepted bywas filed on January 30, 2019. On February 21, 2019, the Washington Commission would resolve all but fourapproved the settlement with one condition: 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.

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 contested issues betweennew corporate tax rate.  PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the settling parties.impacts of tax reform.  The settlement agreement providesdeferred 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 weighted cost of capital of 7.60% or 6.55% after-tax,rate change for electric and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariffcustomers 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 that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM,rates to reflect the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.new corporate tax rates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
Electric:   
May 1, 2018(3.4)% $(72.9)
Natural Gas:   
May 1, 2018(2.7) (23.6)

Decoupling Filings
While fluctuations in weather conditionsOn 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 affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardlessand electric fixed production energy costs will now be decoupled and recovered on the basis of actual consumption levels. Currently, PSE'sa fixed monthly amount. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy supply costs which are part of thecan also be changed in a power cost adjustment (PCA) and purchased gas adjustment (PGA) mechanisms, are not included inonly rate case (PCORC). Other changes to the decoupling mechanism. PSE has requested thatmethodology approved by the Washington Commission include regrouping of electric energy supply fixed costs be included inand 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 pendingannual 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 as is discussed above.
Under the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing Partyfiled in PSE’s pending GRC is advocating thator after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE’s existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms.
PSE will recover or refund the difference between allowed decoupling revenueover- and the corresponding actual revenue to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. The decoupling mechanism over and underunder- collections will still be collectible or refundable after December 31, 2017,this effective date even if the decoupling mechanism is not extended.
On April 28, 2017,February 21, 2019, the Washington Commission approved PSE's request to change rates under itsthe multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas decoupling mechanism, effective May 1, 2017. The overallallowed delivery revenue per customer was updated to reflect changes represent a rate increase forin the approved revenue requirement. For electric, customers of $41.9 million, or 2.0%, annually, and a rate increase for natural gas customers of $22.4 million, or 2.4%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2016. As a result, PSE filed with the Washington Commission a reduction in electric decoupling deferral and revenue of $11.9 million and a reduction in natural gas decoupling deferral and revenue of $2.2 million. This was included as a reductionthere were no changes to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related capallowed fixed power cost revenue. The changes took effect on increases in total revenue.  This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2017 rate increase is $47.4 million for natural gas revenue that was accrued through December 31, 2016. The amount not recovered in 2017 may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  March 1, 2019.
Due to the 3.0% cap on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet,On September 30, 2019, PSE performed an analysis as of September 30, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period.period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and 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 current deferred revenues forof electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, there were no adjustmentsadjustment was booked to 20172019 decoupling revenues other than to record the previously unrecognized decoupling deferrals of $20.8 million.
Other Proceedings
Microsoft
On October 7, 2016, PSE filed a tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to the case reached an all-party settlement that would convert the tariff to a special contract only allowing retail access for the loads of the Microsoft Corporation currently being served under PSE’s electric Schedule 40. The specialrevenue.

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

Voluntary Long-Term Renewable Energy
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)1
Electric:   
May 1, 20190.9% $20.6
May 1, 2018(1.1) (25.2)
Natural Gas:   
May 1, 2019(5.3)% $(45.9)
May 1, 20181.7 15.9
On September 28, 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product, effective September 30, 2016. This provides customers with energy choices to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh) and government customers. Approximately 135 MW of new wind generation facilities will be constructed in the region by a developer under contract to PSE which will meet the demand for this voluntary renewable energy product project._______________
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.

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

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

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

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

OnIn September 30, 2016, PSE filed an accounting petition with the Washington Commission which requestsrequested 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 iswas January 1, 2017, through December 31, 2017, when rates gowent into effect from PSE's 2017 GRC. OnIn November 10, 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 nine months ended September 30, 2017,2019, in its PCA mechanism, PSE under recoveredunder-recovered its power costs by $8.9$48.9 million of which no$19.5 million amount was apportioned to customers. This compares to an over recoveryunder-recovery of power costs of $1.4$7.7 million for the nine months ended September 30, 20162018 of which no amounts were apportioned to customers. Although load increasedPower costs have been higher than the allowed base line in 2017 compared2019 which has led to 2016 that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the PCA deferral causing an under-collection compared to the prior year. Actual power costs were less than baseline rates in 2018 which caused an over-collection. Load increased 4.2% year over year changewhich is one driver of increased power cost. This was duedriven by colder temperatures in February and early March. Additionally, power prices increased during the period as compared to the 2017 mechanism where fixed production costs, other costsprior year. Increase in prices are due to: (i) Cold weather in February and adjustments are no longer included.early March which drove regional loads up; (ii) Westcoast pipeline capacity limitations 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 mechanism is now comparing variable PCA costs usingrelative prices of natural gas and power reduced the variable costs portionsupply of natural gas-fired generation and increased the demand for market power, increasing prices.


Power Cost Adjustment Clause Filing
PSE updated its rates under Schedule 95 its Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the baseline rate.  Microsoft Special Contract.
The fixed costs will become part offollowing table sets forth the decoupling mechanism, assumingrate change approved by the decoupling mechanism continues after its review inWashington Commission and the GRC, but until thencorresponding expected annual impact on PSE’s revenue based on the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
July 1, 2019(1.2)% $(24.9)

Electric Conservation Rider
On April 28, 2017,The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, as well as actual compared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission approved PSE's request to change rates under its electric conservation rider mechanism,and the corresponding expected annual impact on PSE’s revenue based on the effective May 1, 2017. The rate filing requests recovery of estimated program year expenditures as well as a true-up for actual costs and collections for the conservation program for the prior period which would result in a rate increase for electric customers of $16.5 million, or 0.7%, annually.dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase
(Decrease)
in Revenue
(Dollars in Millions)
May 1, 2019(0.9)% $(17.5)
May 1, 2018(0.8) (18.0)

Electric Property Tax Tracker Mechanism
On April 28, 2017,The purpose of the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism effective May 1, 2017.  The approved filing incorporatesis to pass through the effectscost of an increase toall property taxes paidincurred by the Company. The mechanism 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 well as true-ups toa tracker rate schedule and collects the ratetotal amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year which would result in ayear.
The following table sets forth property tax tracker mechanism rate decrease for electric customers of $0.9 million, or 0.04%, annually.adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective 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
On October 31, 2017, PSE filed with the Washington Commission an annual true-up and rate filing to PSE'sThe Federal Incentive Tracker Tariff passes through to customers the benefits associated with an effective date of January 1, 2018.the wind-related treasury grants. The proposed true-up filing as originally filed, resultedresults in a total credit of $48.2 million to be passed back to eligible customers over the twelve months beginning January 1, 2018. The total credit includes $37.8 million which represents thefor pass-back of treasury grant amortization and $10.4 million representspass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the pass through of interest. This filing represents an overall averageforecasted 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 increase of 0.2%, annually.change to be effective May 1, 2018 to recognize the decrease in the federal corporate income tax rate from 35% to 21%.
On December 22, 2016,
The following table sets forth the federal incentive tracker tariff revenue requirement proposed and approved by the Washington Commission approvedand the corresponding expected annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with animpact on PSE’s revenue based on the effective date of January 1, 2017. The true-up filing resulted in a total credit of $51.7 million to be passed back to eligible customers over the twelve months beginning January 1, 2017.  The total credit includes $38.1 million which represents the pass-back of grant amortization and $13.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2016 rate period.  This filing represents an overall average rate increase of 0.3%, annually.dates:
Effective 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
On September 28, 2017,The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration.  Rates change biennially on October 1.
The following table sets forth residential exchange benefit adjustments approved by the Washington Commission approvedand the rate filing to PSE's Residential Exchange Benefit Tariff, with ancorresponding expected annual impact on PSE’s revenue based on the effective date of October 1, 2017. The filing resulted in a total credit of $80.8 million to be passed back to eligible customers over the twelve months beginning October 1, 2017.  This filing represents an overall average rate decrease of 0.6%, annually.dates:
On September 24, 2015, the Washington Commission approved the rate filing to PSE's Residential Exchange Benefit Tariff, with an effective date of October 1, 2015. The filing resulted in a total credit of $76.4 million to be passed back to eligible customers over the twelve months beginning October 1, 2015.  This filing represents an overall average rate increase of 2.4%, annually.

Power Cost Update Compliance Filing
On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission's Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC. The filing requested a reduction in Schedule 95 rates of $37.3 million or an overall rate decrease of 1.7% annually. A corresponding reduction in the PCA Mechanism Baseline Rate used to track the PCA imbalance for sharing was also requested in this filing. PSE’s rate filing became effective on December 1, 2016 by operation of law.
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
On April 28, 2017, the Washington Commission approved PSE's annual filing request to change rates under itsThe natural gas conservation rider mechanism, effectivecollects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 2017. The rate filing requests recovery of estimated programto collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year, expenditures as well as a true-up for actual costscompared to the forecasted load set in rates.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and collections for the conservation program forcorresponding expected annual impact on PSE’s revenue based on the prior period which would result in a rate decrease for natural gas customers of $1.0 million, or 0.1%, annually.effective dates:
 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
On April 28, 2017,The purpose of the Washington Commission approved PSE's annual filing request to change rates under its natural gas property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism 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 rate from the prior year.

The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective May 1, 2017, which would result in a rate decrease for natural gas customers of $1.1 million, or 0.1%, annually.dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2019(0.2)% $(1.6)
May 1, 2018(0.2) (2.2)

Natural Gas Cost Recovery Mechanism
On October 26, 2017, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2017. The purpose of this filingthe cost recovery mechanism (CRM) is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.
The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:
Effective DateAverage
Percentage
Increase (Decrease)
in Rates		 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 20190.8% $7.0
November 1, 20180.5 5.0

Purchased Gas Adjustment
PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the CRMWashington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1st 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 an annual revenue increaseone of $4.9 million, or 0.5%, annually.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.
On October 27,24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates with the rate change taking effect 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 of 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 two years period instead of historic one year from November 2019 through October 2021.

The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
 
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 201913.4% $118.3
May 1, 20196.3 54.0
November 1, 2018(10.9) (98.4)

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 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 CRM natural gas tariff filingrevision to create an additional voluntary renewable energy product. This provides customers with an effective date of November 1, 2016. The purpose of this filing iselectric generation resource options to recover capitalhelp them meet their sustainability goals. Incremental costs related to enhancing the safety of the natural gas distribution system.  The impactprogram will be allocated to the CRM ratesvoluntary participants of the program as is anthe case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual revenue increaseloads 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 $5.6 million, or 0.6%, annually.approximately 136.8 MW that will be constructed in the region by a developer under contract to PSE to meet the demand for this voluntary renewable energy product. 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.

Purchased Gas Adjustment
On October 26, 2017,In July 2018, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective datea second phase of Novemberthe Green Direct product. The phase 2 offering will be a blend of the phase 1 2017, which reflects changes in wholesale natural gaswind and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $30.8 million, or 3.3%, annually with no impact on net operating income.
Ona solar project. In October 27, 2016,2018, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective dateexpansion of Novemberthe solar project from 120 MW to 150 MW. Phase 1 2016,customers will receive wind through 2020; and then will receive the blended energy in 2021. Open enrollment for phase 2, which reflects changesis fully subscribed, began on August 31, 2018. Twenty customers will start receiving energy through phase 2 of the program in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $4.1 million, or 0.4%, annually with no impact on net operating income.2021.

For additional information, see Note 6,7, "Regulation and Rates" to the consolidated financial statements included in Item 1 of this report.

Other Factors and Trends
Access to Debt Capital
PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such 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, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. As of September 30, 2017, PSE's credit facilities

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

Regulatory Compliance Costs and Expenditures
PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
Compliance with these or other future 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. Further, PSE also faces increasing competition for sales to its retail customers.  Alternativecustomers through alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.methods. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE. 

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


Electric Margin
Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory.
The following tablechart displays the details of PSE's electric margin changes:changes for the three months ended September 30, 2018 and 2019:
chart-c0a9306ceae056bf862.jpg
Electric MarginThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Electric operating revenue:          

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

Three Months Endedmonths ended September 30, 20172018 compared to 20162019
Electric Operating Revenue
Electric operating revenues increased $42.2decreased $20.6 million from the prior year primarily due to decoupling revenue of $13.6 million, highera decrease in electric retail sales of $13.0$19.0 million, a decrease in other revenues of $8.4 million and decrease in other decoupling revenue of $7.9$3.3 million; partially offset by an increase in sales to other utilities of $6.7 million and other electric operating revenuesan increase in decoupling revenue of $3.6$3.3 million.  These items are discussed in detail below.
Electric retail sales increased $13.0decreased $19.0 million primarily due to a $7.0decrease in rates of $11.9 million increase inand a decrease of $7.1 million from reduced retail electricity usage of 67,864 Megawatt Hour (MWhs) related1.6% compared to average retailthe prior year. The reduction in usage was due to a decrease of commercial, industrial and residential use per customer growth of 13,828 customers, or 1.2%;2.4%, 0.9% and 0.7%, respectively, which was driven by a decrease in heating degree days of 11.2% and partially offset by an increase in ratesretail customers of $6.0 million.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 $6.7 million due to a 49.3% increase in volumes sold 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 $13.6$3.3 million, dueprimarily attributable to ana $2.7 million increase of $15.7 million in decoupling revenue associated with thePCA fixed cost deferral of the PCA mechanism in 2017. This was partially offsetrevenues, driven by $2.1 million in lower decoupling deferrals in 2017 compared to 2016 due to higher electricitydecreased usage, as noted above.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 $7.9by $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 reduced sharinga decrease in production tax credit (PTC) deferral revenue of rate$8.5 million for the re-purpose of return (ROR) excess earningsthe PTCs, a decrease in non-core gas sales of $10.2$2.3 million from over earningsand a decrease in 2016 as comparedgreen energy option revenue of $1.6 million partially offset by an increase in tax reform deferrals returned to no earnings sharingcustomers in 2017. This2019 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 decoupling cash collections$22.6 million of $1.1 million as compared to 2016 due to an additional $9.0 million being set into rates.
Other electric operating revenue increased $3.6 million primarily due to generation of a production tax credit (PTC) deferral of $5.0 millionfuel expense. These items are discussed in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017. This was partially offset by a decrease in net wholesale natural gas sales of $1.8 million.detail below.

Electric Energy Costs
Purchased electricity expense increased $21.0decreased $41.5 million primarily due to a $13.9 million increase primarily related to long-terman 18.1% decrease in wholesale electricity purchases and a $4.9 million12.0% 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 energy imbalance market (EIM) purchases. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind production of 21.3% and lower production at the combustion turbines of 7.8% resultedturbine generation, as noted in the need to purchase power. PSE began participating in the EIM operated by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand and generation resources.section below.
Electric generation fuel expense decreased $3.9increased $22.6 million primarily due to a number of factors including a $3.3 million decrease in the total cost of natural gas burned driven by lower volumes burned in 2017 as compared to 2016. Also contributing to the decrease in fuel costs is a $3.4 million decrease in the cost of coal burned from lower average prices offset by a $1.9$10.6 million increase in the lowercombustion turbine generation costs primarily driven by an increase in generation of cost or market inventory adjustment for coal recorded in 2017 compared to 2016.20.0% 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 Endedmonths ended September 30, 20172018 compared to 20162019
Electric Operating Revenue
Electric operating revenues increased $113.7$87.8 million primarily due to higher retail sales of $86.7 million,transportation and other operating revenues of $32.1$99.5 million, sales to other utilities of $23.1 million, decoupling revenue of $6.7 million, and other decoupling adjustmentsrevenue of $2.8 million;$3.6 million, partially offset by decreases in decoupling revenuelower electric retail sales of $9.3$45.1 million.  These items are discussed in detail below.
Electric retail sales increased $86.7decreased $45.1 million primarily due to a $77.5decrease in rates of $52.2 million, offset by an increase inof $7.1 million from additional retail residential electricity usage of 743,073 MWhs related1.9% compared to a 28.0% increase in heating degree days; andthe 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% increase in sales volume. During the 1st 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 was increase in volumes from an additional 111.8% of combustion turbine generation as a result of favorable heat rates of $9.2 million.and increased demand for market power.
Decoupling revenue decreased $9.3increased $6.7 million, duethe combination of a $1.4 million decrease in delivery deferral revenues and an $8.1 million increase in PCA fixed cost deferral revenues. The decrease in delivery deferral revenues resulted from a more significant decline in allowed revenues than actual revenues year-over-year, attributable to $19.8 million in lower decouplingallowed rate per customer. For PCA fixed cost deferrals, in 2017 comparedactual revenues declined significantly, attributable to 2016 due to higher electricitylower rates, partially offset by increased usage, as noted above. This was partially offset by an increase of $10.5 millionabove in decouplingthe retail revenue associated withsection, resulting in less over collection in the fixed cost deferral ofcurrent year than in the PCA mechanism in 2017.prior year.

Other decoupling revenue increased $2.8$3.6 million, primarily due to decreases in ROR excess earnings sharing of $8.6 million due to no expectation to over earn in 2017 and 24-month revenue reserve of $1.6 million from no reserve in 2017. This was partially offset by a $7.4 million increase year-over-year related to a decrease in current year amortization of previous years' decoupling cash collectionsdeferrals. This resulted from lower amortization rates, partially offset by increased usage. This increase was offset in part by a $4.1 million decrease related to earnings in excess of allowed ROR. In 2018, earnings in excess of allowed ROR of $7.5 million was returned to customers, as compared to 2016 due to an additional $9.0$3.5 million being set into rates.returned in the current year.
Other electric operatingTransportation and other revenue increased $32.1$99.5 million primarily due to an increase in net wholesale non-core natural gas sales of $17.3$84.4 million and a reduction in tax reform deferrals for revenue subject to refunds of $32.2 million; partially offset by a change in PTC deferral revenue of $15.8$18.5 million for the re-purpose of the PTCs. The increase in 2016net wholesale non-core gas sales was due to an approximately 143% increase in the average price of the non-core gas sold in 2019 as compared to no PTC deferral2018, offset by a 12% decrease in 2017 since the PTC generation period expired in the first quarter of 2017.

Electric Energy Costs
Purchased electricity expense increased $69.0 million primarily due to a $45.5 million increase related to long-term purchases, a $13.3 million increase in EIM purchases,sales volume and a $8.3$32.0 million increase in the power exchange contract with Pacific Gas & Electric Company. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind production of 17.4% and lower production at the combustion turbines of 26.3% resulted in the need to purchase power. PSE began participating in the EIM operated by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand and generation resources.



Electric generation fuel expense decreased $13.6 million primarily due to a $10.7 million decrease in the total cost of naturalthe non-core gas burnedsold due to an approximately 67% increase in the average cost of the gas sold driven by lower volumes burned offset by an increase in the average price of non-core gas purchases. The higher gas prices occurred in early 2019 and were due to the continuing effects of the late 2018 Enbridge pipeline rupture which led to a decrease in pipeline capacity in the region at the same time that there were compressor issues at a gas storage facility which limited natural gas burneddeliverability, and a $2.9higher than expected load due to cold weather during that time.

Electric Power Costs
Electric power costs increased $134.2 million decreaseprimarily due to an increase of $69.9 million of purchased electricity costs and an increase of $65.3 million of electric generation fuel expense. These items are discussed in the cost of coal burneddetail below:
Purchased electricity expense increased $69.9 million primarily due to a lower average30.8% increase in wholesale prices partially offset by an 11.4% decrease in wholesale electricity purchases. The decrease in purchases was primarily driven by a decrease in hydro purchases at Mid-Columbia of coal burned27.0%, due to unfavorable hydro conditions, driving an increase in 2017 comparedcombustion turbine generation, which decreased the need to 2016. 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.
Residential exchange creditsElectric generation fuel expense increased $3.7$65.3 million resulting from increasedprimarily due to a $49.6 million increase in combustion turbine generation costs primarily driven by an increase in generation of 46.0% as a result of favorable heat rates, unfavorable wholesale electricity usage as rates remain consistent in both periods. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income. The Northwest Power Act, through the REP, provides access to the benefitsprices, reduced hydro purchases of low-cost federal power for residential27.0% and small farm customersreduced hydro and wind generation of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA21.6% and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.12.9%, respectively.


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

The following tablechart displays the details of PSE's natural gas margin:
margin changes for the three months ended September 30, 2018 and 2019:
Natural Gas MarginThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Natural gas operating revenue:          
Residential sales$65,793
 $66,480
 $(687) $467,725
 $376,310
 $91,415
Commercial sales36,617
 36,862
 (245) 194,716
 162,135
 32,581
Industrial sales3,390
 3,349
 41
 15,258
 13,742
 1,516
Total retail sales105,800
 106,691
 (891) 677,699
 552,187
 125,512
Transportation sales5,285
 4,897
 388
 16,218
 15,007
 1,211
Decoupling revenue4,840
 3,709
 1,131
 1,482
 39,739
 (38,257)
Other decoupling revenue1
(7,315) (3,904) (3,411) (12,932) (14,565) 1,633
Other2,906
 3,065
 (159) 9,218
 8,941
 277
Total natural gas operating revenues2
111,516
 114,458
 (2,942) 691,685
 601,309
 90,376
Minus purchased natural gas energy costs2
32,224
 34,041
 (1,817) 248,208
 205,418
 42,790
Natural gas margin3
$79,292
 $80,417
 $(1,125) $443,477
 $395,891
 $47,586
            
Natural Gas Volumes           
(Therms in Thousands):           
Residential42,150
 44,650
 (2,500) 412,325
 331,180
 81,145
Commercial firm31,861
 31,629
 232
 194,446
 159,096
 35,350
Industrial firm4,048
 3,626
 422
 18,444
 16,015
 2,429
Interruptible6,877
 9,452
 (2,575) 33,921
 33,829
 92
Total retail natural gas volumes, therms84,936
 89,357
 (4,421) 659,136
 540,120
 119,016
Transportation volumes53,992
 52,298
 1,694
 173,042
 170,548
 2,494
Total natural gas volumes138,928
 141,655
 (2,727) 832,178
 710,668
 121,510
chart-c98e25c3f61257fcb55.jpg
_______________
1
*Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.
Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.
2
As reported on PSE’s Consolidated Statement of Income.
3
Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.





Three Months Endedmonths ended September 30, 20172018 compared to 20162019
Natural Gas Operating Revenue
Natural gas operating revenue decreased $2.9increased $1.4 million primarily due to a decreasean increase of $3.4$3.3 million in other decoupling revenue and an increase of transportation and other revenue of $1.4 million; partially offset by a decrease of $0.9$1.7 million in decoupling revenue and a decrease of $1.6 million in total retail sales due to a decrease of natural gas usage; partially offset by a $1.1 million increase in decoupling revenue.sales. These items are discussed in detail below.
Natural gas retail sales revenue decreased $0.9$1.6 million due to a decrease in rates of $6.8 million partially offset by an increase in natural gas load of 5.0%, or $5.2 million of natural gas sales. Natural gas load increased primarily due to the increase in average therms used per residential, commercial and industrial customers of 3.7%, 6.2% and 63.8%, respectively compared to 2018, as a result of a 1.3% increase in natural gas customers, which increased the natural gas heating load compared to prior year. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate changes.
Decoupling revenue decreased $1.7 million. This is primarily attributable to higher natural gas usage, as noted above in the retail revenue section. This resulted in actual natural gas revenues being greater than allowed natural gas revenues in the current year, where as in the prior year allowed natural gas revenues were greater than actual natural gas revenues.
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 $5.3tax 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 $2.4 million fromdue to a reduction of 2,727 therms sold from lower heating degree daysdecrease in 2017;natural gas costs included in PGA rates partially offset by an increase in natural gas usage of $4.4 million due to5.0%. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for rate adjustments.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
_______________
Other*Includes decoupling revenue decreased $3.4 million primarily due to increasedcash collections, ROR excess earnings, sharing of $6.2 million of which $4.3 million was accrued for over earnings in 2017. This was partially offset by a decrease of $2.7 million inand decoupling 24-month revenue reserve as compared to 2016 as no reserve was recorded in 2017.reserve.

Nine Months Endedmonths ended September 30, 20172018 compared to 20162019
Natural Gas Operating Revenue
Natural gas operating revenue increased $90.4decreased $31.0 million primarily due to an increasea decrease of $125.5$37.2 million in total retail sales due to additionala decrease of natural gas usagerates and an increasea decrease of $5.5 million in other decoupling revenue, of $1.6 million; partially offset by a $38.3 million reductionan increase in decoupling revenue.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 $125.5 million primarily due to anthe increase in average therms used per residential, commercial and industrial customers of $121.7 million from an additional 121,510 therms sold related4.7%, 4.2%, and 6.4%, respectively, compared to 2018 as a 28.0%result of a 3.4% increase in heating degree days;days in the 1st quarter of 2019 as well as 1.3% increase in natural gas customers. See Management's Discussion and an increaseAnalysis, "Regulation and Rates" included in Item 2 of $3.8 million due tothis report for rate adjustments.
Decoupling revenue decreased $38.3 million due to lower load volumes in 2016, which caused actual revenue to be below the allowed revenue, resulting in higher decoupling revenue of $39.7 million. In 2017, higher load volumes caused actual revenue to be closer to allowed revenue resulting in lower decoupling revenue of $1.5 million.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 $1.6year-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 a $22.9 million reversaltax reform deferrals returned to customers for revenue subject to refund of previously deferred revenues related to the 24-month revenue reserve.  The increase was partially offset by an increase in decoupling cash collections of $13.0 million due to an additional $6.0 million being set in rates and increased ROR excess earnings sharing of $8.2 million of which $10.1 million was accrued for over earnings in 2017.$12.2 million.

Natural Gas Energy Costs
Purchased natural gas expense increased $42.8decreased $43.4 million directly relateddue to a 22.7%decrease in natural gas costs included in PGA rates partially offset by an increase in natural gas usage.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 tablechart displays the details of PSE's operating expenses and other income (deductions) for the three and nine months ended September 30, 20172018 and 2016:
Puget Sound EnergyThree Months Ended September 30, Nine Months Ended
September 30,
(Dollars in Thousands)2017 2016 Change 2017 2016 Change
Operating expenses: 
  
  
      
Net unrealized (gain) loss on derivative instruments$(23) $6,327
 $(6,350) $23,098
 $(57,218) $80,316
Utility operations and maintenance141,003
 138,265
 2,738
 438,622
 422,273
 16,349
Non-utility expense and other9,994
 8,620
 1,374
 27,857
 26,474
 1,383
Depreciation and amortization120,829
 110,022
 10,807
 355,538
 328,809
 26,729
Conservation amortization25,395
 21,800
 3,595
 85,847
 77,551
 8,296
Taxes other than income taxes66,367
 65,268
 1,099
 262,099
 235,431
 26,668
Other income (deductions):           
Other income6,778
 6,131
 647
 18,861
 19,184
 (323)
Other expense(2,878) (5,025) 2,147
 (6,134) (8,488) 2,354
Interest expense(56,745) (58,212) 1,467
 (172,467) (174,673) 2,206
Income tax expense14,424
 8,393
 6,031
 109,015
 117,533
 (8,518)
2019:

chart-46d33384b19050e7b47.jpg
Three Months Endedmonths ended September 30, 20172018 compared to 20162019
Other Operating Expenses
Net unrealized (gain) loss on derivative instruments increased $6.4decreased $28.8 million fromto a net loss of $6.3$14.7 million. The primary 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 million in gains and $1.2 million in losses, respectively, further reduced the net unrealized (gain) loss.
Utility operations and maintenance expense increased $3.5 million primarily due to an increase in (i) hardware and software maintenance costs and IT expense of $3.5 million due to a $6.6 millionan increase in settlementsIT projects; (ii) an increase in damage and liability claims of contracts with previously unrealized losses.$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-Utility and other expense increased $1.3 million primarily due to an increase in the long-term incentive plan accrual of $3.9 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.

Depreciation and amortization expense decreased $15.3 million primarily driven by: (i) a decrease in amortization of PTC regulatory liability of $8.5 million in 2019 as compared to 2018, (ii) a decrease of $7.6 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 $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; partially offset by (vi) an increase in common amortization of $8.1 million driven by net additions of $129.9 million of software; (vii) electric depreciation expense increased $10.8$4.1 million primarily due to net asset additions to distribution of $213.6 million and (viii) an increase of $3.7 million of amortization expense related to an increase of computer software assets, $2.2 million ofin natural gas depreciation expense relatedof $2.1 million primarily due to net asset additions to distribution of $183.0$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 electric distribution$1.3 million and general assets and an increasestate excise taxes of $1.7$0.8 million as a result of a decrease in retail revenue, as well as a decrease of $0.4 million related to an additional $174.8 million of natural gas distribution assets.the property tax tracker.

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 increased $6.0decreased $3.3 million primarily driven by highera decrease in pre-tax book income.


Nine Months EndedThe following chart displays the details of PSE's operating expenses and other income (deductions) for the nine months ended September 30, 20172018 and 2019:

chart-7c520d73fe3a5fa2bee.jpg

Nine months ended September 30, 2018 compared to 20162019
Other Operating Expenses
Net unrealized (gain) loss on derivative instruments decreased $80.3$51.8 million to a net loss of $23.129.9 million. The primary drivers for the change related to net settlements of $50.9 million and $22.9 million of which $57.2 million was due to decreases in average forward market prices of wholesale electricityelectric and natural gas and $23.1 milliontrades 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 decrease in settlements of contracts with previously unrealized losses.$22.0 million increase.
Utility operations and maintenance expense increased $16.3 million, which was primarily due to the following: increases in administrative and general and customer service expense of $21.9$10.2 million primarily due to $7.1an 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 rentbad debt expense primarily at the corporate office locations, $5.3 milliondue to an improved collection process and (vii) a decrease in underground cable expense primarily for liability claimsof $3.3 million.
Non-utility and insurance premium, $4.6 million of pensions and benefitsother expense increased $3.9 million primarily due to an increase in the long-term incentive plan accrual of general plant maintenance expense and $3.1$6.5 million of outside services employed expenses. This wasdue to an increase in long-term incentive plan awards in 2019 partially offset by a decrease in electric transmission and distributionbiogas gas purchase expense of $8.4$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 $26.7$7.9 million primarily due to net asset additions to distribution of $213.6 million and (viii) an increase of $11.6 million of amortization expense related to an increase of computer software assets, $8.7 million ofin natural gas depreciation expense of $5.8 million primarily due to net asset additions to distribution of $253.7 million of electric transmission, distribution and general assets and an increase of $5.0 million of depreciation expense due to net additions of $174.8 million of natural gas distribution assets.
$210.5 million.
Taxes other than income taxes increased $26.7decreased $8.0 million primarily due to increasesdecreases in municipal taxes of $9.2$4.6 million and state excise taxes of $8.5$3.1 million bothas a result of a decrease in retail revenue, as well as a decrease of $2.2 million related to increased revenue and an increase of $8.8 million inthe property taxes related to increased property values and expected tax rates.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 expensedecreased $8.5$10.9 million primarily driven primarily driven by lowera decrease in pre-tax book income.

Puget Energy
Primarily, all operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and nine months ended September 30, 20172018 and 20162019 are as follows:

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

512
 (316) 828
Non-hedged interest rate swap (expense)—
 563
 (563) 28
 (651) 679
Interest expense1
(28,913) (28,384) (529) (85,451) (84,451) (1,000)
Income tax benefit (expense)9,600
 7,583
 2,017
 28,527
 26,154
 2,373
Puget Energy net income (loss)$12,836
 $2,335
 $10,501
 $175,662
 $208,074
 $(32,412)
chart-25790516d3c8515c9c0.jpg
_______________
1Three months ended September 30, 2018 compared to 2019
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on long-term debt.

Summary Results of Operation
Three Months Ended September 30, 2017 compared to 2016
Puget Energy’s net income increaseddecreased for the three months ended September 30, 20172019 by $10.5$17.4 million primarily due to a decrease in PSE's increasenet income compared to the same period in net income. No additional factors significantly impacted the prior year.


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

chart-f140ab5ea9525b5891b.jpg


Nine Months Endedmonths ended September 30, 20172018 compared to 20162019
Summary Results of Operation
Puget Energy’s net income decreased for the nine months ended September 30, 20172019 by $32.4$68.8 million primarily due to PSE'sa decrease in PSE's net income. Noincome 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 factors significantly impacted Puget Energy's net income.$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
In additionDuring the nine months ended September 30, 2019, there were no material changes to the contractual obligations and consolidated commercial commitments disclosed in Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Annual Report on Form 10-K for the yearperiod ended December 31, 2016, during the nine months ended September 30, 2017 the Company has entered into two new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.2018.

The following are the Company's aggregate availability under commercial commitments as of September 30, 2017:2019:
Puget Sound Energy and
Puget Energy
Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)Total 2017 2018-2019
 2020-2021
 Thereafter
PSE working capital facility1
$650,000
 $—
 $650,000
 $—
 $—
PSE energy hedging facility1
350,000
 —
 350,000
 —
 —
Inter-company short-term debt2
30,000
 —
 —
 —
 30,000
Total PSE commercial commitments$1,030,000
 $—
 $1,000,000
 $—
 $30,000
Puget Energy revolving credit facility3
716,936
 —
 716,936
 —
 —
Less: Inter-company short-term debt elimination2,3
(30,000) —
 —
 —
 (30,000)
Total Puget Energy commercial commitments$1,716,936
 $—
 $1,716,936
 $—
 $—
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
 $—
_______________
1
For further discussion, see Management's Discussion and Analysis, "Financing Program" in Item 2.
For more information, see "Financing Program - Puget Sound Energy - Credit Facilities - set forth below
2
For more information, see "Financing Program - Puget Sound Energy - Demand Promissory Note - set forth below.
3
For more information, see "Financing Program - Puget Energy - Credit Facility - set forth below.

Off-Balance Sheet Arrangements
As of September 30, 2017,2019, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition, other than previously disclosed items in Note 8, "Commitment and Contingencies" to the consolidated financial statements included in Item 1 of this report.condition.

Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to support reliable energy delivery, meet regulatory requirements, support customer growth and customer growth.to improve energy system reliability.  Construction expenditures, excluding equity allowance for funds used during construction (AFUDC),AFUDC, totaled $677.0$680.1 million for the nine months ended September 30, 2017.2019. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections          
(Dollars in Thousands)2017 2018 20192019 2020 2021
Total energy delivery, technology and facilities expenditures$1,092,000
 $972,000
 $809,000
$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.  


Capital Resources
Cash from Operations
Puget Sound EnergyNine Months Ended September 30, 2017 Nine Months Ended
September 30,
(Dollars in Millions)2017 2016 Change2019 2018 Change
Net income$222,846
 $256,382
 $(33,536)$123,720
 $193,709
 $(69,989)
Non-cash items1
562,232
 455,355
 106,877
531,225
 493,821
 37,404
Changes in cash flow resulting from working capital2
164,451
 66,718
 97,733
(163,835) 158,184
 (322,019)
Regulatory assets and liabilities(83,370) (138,096) 54,726
(46,993) (22,545) (24,448)
Other noncurrent assets and liabilities3
(33,734) 10,128
 (43,862)
Other non-current assets and liabilities3
(13,028) (8,356) (4,672)
Net cash provided by operating activities$832,425
 $650,487
 $181,938
$431,089
 $814,813
 $(383,724)
_______________
1 
Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and AFUDC-equity.other miscellaneous non-cash items.
2
Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayment, PGA, accounts payable and accrued expenses.
3
Other non-current assets and liabilities include funding of pension liability.

Nine months ended September 30, 2019 compared to 2018
Cash generated from operations for the nine months ended September 30, 2019 decreased by $383.7 million including a net income decrease of $70.0 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 million primarily due to a $51.8 million change from a net unrealized gain on derivative instruments of $22.0 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 million, offset by decreases in depreciation and amortization of $2.7 million, conservation amortization of $11.4 million, and deferred income taxes of $14.4 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 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 $122.9 million was primarily due to payment of significant power and natural gas costs accrued at December 31, 2018 that were paid in 2019. Finally, cash outflows associated with taxes payable increased by $47.8 million, as property taxes were paid in September of 2019 as compared to October of 2018.
Cash flows resulting from regulatory assets and liabilities decreased $24.4 million primarily due to an increase in the power cost adjustment mechanism due to actual power costs being above power baseline costs. For further details, see Management's Discussion and Analysis, "Electric Margin" in Item 2.
Puget EnergyNine Months Ended
September 30,
(Dollars in Millions)2019 2018 Change
Net income$(63,961) $(65,138) $1,177
Non-cash items1
5,990
 616
 5,374
Changes in cash flow resulting from working capital2
(10,938) 2,058
 (12,996)
Regulatory assets and liabilities—
 —
 —
Other noncurrent assets and liabilities3
(8,047) (10,016) 1,969
Net cash provided by operating activities$(76,956) $(72,480) $(4,476)
_______________
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, purchased gas adjustments,PGA, accounts payable and accrued expenses.
3  
Other noncurrentnon-current assets and liabilities include funding of pension liability.


Nine Months Endedmonths ended September 30, 20172019 compared to 20162018
Cash generated from operations for the nine months ended September 30, 2017 increased2019, in addition to the changes discussed at PSE above, decreased by $181.9$4.5 million including a net income decrease of $33.5 million.compared to the same period in 2018.  The following are significantchange was primarily impacted by the factors that impacted PSE's cash flows from operations:explained below:
Cash flow resulting from non-cash items increased $106.9$5.4 million primarily due to changes in derivative instruments of $80.3 million and depreciation and amortization of $26.7 million.
Cash flow resulting from working capital increased $97.7 million due to changes in accounts receivable, unbilled revenue, materials and supplies, prepayments, purchased gas adjustments and accrued expenses.
Cash flow resulting from regulatory assets and liabilities increased $54.7 million primarily due to changes in decoupling and derivatives offset by changes in purchased gas adjustments.
Cash flow resulting from other noncurrent assets and liabilities decreased $43.9 million primarily due to changes in asset retirement obligations and pension funding partially offset by changes in long-term deferred credits.
Puget EnergyNine Months Ended September 30, 2017
(Dollars in Millions)2017 2016 Change
Net income$175,662
 $208,074
 $(32,412)
Non-cash items1
534,975
 425,634
 109,341
Changes in cash flow resulting from working capital2
151,128
 67,968
 83,160
Regulatory assets and liabilities(83,370) (138,096) 54,726
Other noncurrent assets and liabilities3
(9,725) 6,766
 (16,491)
Net cash provided by operating activities$768,670
 $570,346
 $198,324
_______________
1
Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments and AFUDC-equity.
2
Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, purchased gas adjustments, accounts payable and accrued expenses.
3
Other noncurrent assets and liabilities include funding of pension liability.

Nine Months Ended September 30, 2017 compared to 2016
Cash generated from operations for the nine months ended September 30, 2017 increased by $198.3 million compared to the same period in 2016.  The net difference was primarily impacted by the increase from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below:income taxes.
Cash flow resulting from working capital decreased $14.6 million primarily due to a larger change in accounts receivable.

Cash flow resulting from other noncurrent assets and liabilities increased $27.4$13.0 million primarily due to changes in other property and investments related to Puget LNG.eliminations of PSE's intercompany account receivable balances with PLNG.

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

Puget Sound Energy
Credit FacilitiesFacility
As of September 30, 2017,2019, PSE had two unsecured revolvingan $800.0 million credit facilities which provided, in aggregate, $1.0 billion offacility to meet short-term liquidity needs. These facilities consisted of a $650.0 million revolving liquidity facility (which included a liquidity letter ofThe credit facility and a swingline facility) to be used for general corporate purposes, including as backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which included an energy hedging letter of credit facility). The $650.0 million liquidity facility includedincludes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also hadfacility has an accordionexpansion feature which, upon the banks' approval, would increase the total size of these facilitiesthe facility to $1.5$1.4 billion. TheseOn September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facilities maturefacility was extended for one year. The facility now matures in April 2019.October 2023.
The credit agreements areagreement is syndicated among numerous lenders and containcontains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreementsagreement also containcontains a financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2017,2019, PSE was in compliance with all applicable covenant ratios.
The credit agreements provideagreement provides PSE with the ability to borrow at different interest rate options. The credit agreements allowagreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities.facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.
As of September 30, 2017,2019, no amounts were drawn and outstanding under either facility. No letters ofPSE's credit were outstanding under either facility and $139.0$69.0 million was outstanding under the commercial paper program. Outside of the credit agreements,agreement, PSE had a $3.1$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.
In October 2017, PSE entered into a new $800.0 million credit facility to replace the two existing facilities. The new credit facility consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant, and accordion feature remain substantially the same. The new facility matures in October 2022.

Demand Promissory Note
In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy.  Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE'sPSE’s outstanding commercial paper interest rate or PSE'sPSE’s senior unsecured revolving credit facility.  Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of September 30, 2017,2019, PSE had no outstanding balance under the Note.

Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests at September 30, 2017,2019, PSE could issue:
Approximately $2.6$1.8 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on

approximately $4.3$3.0 billion of electric bondable property available for issuance, subject to a minimuman interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at September 30, 2017;2019; and
Approximately $545.0$591.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $908.3$985.0 million of natural gas bondable property available for issuance, subject to a minimum combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at September 30, 2017.2019.
At September 30, 2017,2019, PSE had approximately $6.9$7.6 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations
On November 21, 2016,August 2, 2019, PSE filed a new shelf registration statement for under which it may issue, as of the date of this report, up to $800.0 million$1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration. The shelf registration will expire in November 2019.August 2022.

Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures.  At September 30, 2017,2019, approximately $674.2$816.5 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciationearnings before interest, tax, depreciation and Amortizationamortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.  The common equity ratio, calculated on a regulatory basis, was 49.4%48.4% at September 30, 20172019 and the EBITDA to interest expense was 5.45.3 to 1.0 for the twelve months ended September 30, 2017.2019.
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.

Long-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-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.

Puget Energy
Credit Facility
AtAs of September 30, 2017,2019, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures April 2018.facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the 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, 2017,2019, there was $83.1$16.9 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of September 30, 2017,2019, Puget Energy was in compliance with all applicable covenants.


Long-Term Debt
In October 2017, April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under 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 September 26, 2019, Puget Energy entered into a new $800.0separate $210.0 million, credit facility to replace the existing facility.three-year term loan agreement with a small group of banks. The terms and conditions, including fees, interest rate options, financial covenant, and accordion feature remain substantially the same. The new facility matures in October 2022.
On May 15, 2017,agreement allows Puget Energy entered intoto borrow at either the banks' prime rate or LIBOR plus a revolving credit agreement with Puget LNG, a wholly owned subsidiary of Puget Energy. Underspread, which will vary as those base rates fluctuate over the agreement,loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy agreedmay request to loanincrease 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 $200.0 million$100.0 million. The proceeds from the term loan were contributed as equity to Puget LNGPSE and used to finance Puget LNG’s portion of the construction costs of a liquefied natural gas facility located at the Port of Tacoma. The interest rate for amounts borrowedrepay outstanding short term debt under the agreement is equal to the one month LIBOR rate in effect on the first day of each month plus the applicable margin Puget Energy would pay on loans under its credit facility. Interest under the agreement is due on the first business day of each quarter and Puget LNG may elect to make payment in kind (PIK) interest payments in which the interest due is added to the balance outstanding under the agreement. The maximum balance outstanding under the agreement, including PIK interest, is $200.0 million.Company's commercial paper program.

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, 20172019.
At September 30, 2017,2019, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

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

Washington Clean Energy Transition 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 Transition 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 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 Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow investor-owned utilities to recover costs in rates for earlier closure of those facilities. Investor-owned utilities will be allowed to earn a rate of return on certain Power Purchase Agreements (PPA's) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.
IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.

Colstrip 
PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. OnIn March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. OnIn July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court onin September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. 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 expects thathas accelerated the Washington Commission will allow full recovery in ratesdepreciation of Colstrip Units 3 and 4, per the terms of the net book value (NBV)GRC settlement, to December 31, 2027.
On June 11, 2019, Talen made a public announcement that Colstrip 1 and 2 will be shut down at retirement and related decommissioning costs consistentthe end of the year due to operational losses associated with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to athe Units. The regulatory asset which represents the expected NBV atassociated with early retirement of Colstrip Units 1 and 2 based on the expected shutdown date of July 1, 2022increased from $130.7 million as of December 31, 2016. Due2018, to a re-estimate of Colstrip Units 1 and 2 Asset Retirement and Environmental obligation (ARO) costs, the regulatory asset account was reduced to $175.0$178.2 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by2019. The Washington Clean Energy Transition Act requires the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as partWashington Commission to provide recovery of the settlement. While PSE has estimatedinvestment, decommissioning, and remediation costs associated with the ARO for Colstrip Units 1 and 2, thefacilities. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

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




Regional Haze Rule
OnIn January 10, 2017, the EPA providedU.S. Environmental Protection Agency (EPA) published revisions to the Regional Haze Rule which were published in the Federal Register.Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. AspectsIn January 2018, EPA announced that it was reconsidering certain aspects of these revisions are currently being challenged by various entities nationwide and a briefingPSE is scheduled forunable to predict the end of July 2017. In the meantime, Montana has indicated that they plan to work on and submit a State Implementation Plan for the second planning period.

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

Clean Air Act 111(d)/EPA Affordable Clean Power PlanEnergy Rule
In June 2014,October 2015, the EPA issued a proposedthe Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includesplants, which included state-specific goals and guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014. The EPA published a final rule on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, signedHowever, after signing a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10,in March 2017, the EPA proposedfinalized a rule to repeal the CPP rule in June 2019
In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule to replace the 2015 CPP. The ACE rule was finalized in June 2019, and is currently accepting comment on the proposal.establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. PSE is still reviewingevaluating the final ACE rule to determine its impact of these developments. However, Washington has moved forward with its own Clean Air Rule (CAR). The potential impacts of the Washington Clean Air Rule are described below.on operations.

Washington Clean Air Rule
The CAR was adopted onin September 15, 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.
The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.
OnIn September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. OnIn September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. While awaitingIn March 2018, the outcomeThurston 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, but no determination by the court has yet been made. The federal court litigation has been held in abeyance pending litigation, the Company has undertaken steps to comply with the first compliance periodresolution of the CAR, which began on January 1, 2017.state case.

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

Currently under construction, theThe Tacoma LNG facility is expected to be operational in 2019.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. AsPer this allocation of September 30, 2017, Puget LNG has incurred $86.5costs, $191.8 million inof construction work in progress and $1.0 million of operating costs related to Puget LNG’sLNG's portion of the Tacoma LNG facility.facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of September 30, 2019. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.



Item 3.     Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.2018.

Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee (EMC) establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.    
PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  

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. 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, 20172019, 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 werehave been no changes in Puget Energy'sEnergy’s internal control over financial reporting that occurred during the period covered by this quarterly reportquarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, itsPuget Energy’s internal control over financial reporting.


Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 20172019, 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.
There werehave been no changes in Puget Sound Energy'sPSE’s internal control over financial reporting that occurred during the period covered by this quarterly reportquarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, itsPSE’s internal control over financial reporting.
In January 2017, Puget Sound Energy implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The new/updated systems were used in preparing financial information for the nine months ended September 30, 2017. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes were being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.

PART II                  OTHER INFORMATION

Item 1.     Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of September 30, 20172019.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitment"Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements in PartItem I.


Item 1A.     Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A, "Risk Factors" of the Company's Annual Report on Form 10-K for the period ended December 31, 2016.

2018.

Item 5.                      Other Information

Departure of Directors and Certain Officers; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

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

Prior to holding his current positions, Mr. King, 33, was a Senior Manager at PricewaterhouseCoopers LLP, a national public accounting firm, since September 2007 where he audited utility, technology and telecommunication companies. Mr. King received a Bachelor’s degree in Accounting and Finance from Ohio University.
No new agreement will be entered into in connection with Mr. King’s appointment to the position of Controller and Principal Accounting Officer, and in addition to his current compensation package, Mr. King will participate in the Company’s Long Term Incentive Plan and other benefit programs of the Company.

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

Also effective November 2, 2017, the sole shareholder of PSE appointed and elected Barbara Gordon to the Board of Directors of PSE. Initially, Ms. Gordon will not be appointed to any committees of the Board.
Ms. Gordon was most recently the Executive Vice President and Chief Customer Officer of Apptio, which position she held from 2016 through 2017, when she retired. Prior to her service at Apptio, she served as Senior Vice President and Chief Operating Officer at Isilon/EMC from 2013 to 2016 and as Corporate Vice President, Worldwide Customer Service and Support at Microsoft from 2003 to 2013. Ms. Gordon also currently serves as Vice President on the Board of Directors for the Seattle-King County Habitat for Humanity and chairs their Strategy Committee.
The compensation offered to Ms. Gordon for her service as a director of PSE will be the same as that offered to all non-employee independent board members of the Company, pursuant to the director compensation schedule filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015.



Item 6.     Exhibits

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


EXHIBIT INDEX

3(i).1
Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2
Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1
Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2
Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
10.110.1*
CreditTerm Loan Agreement, dated October 25, 2017as of September 26, 2019. by and among Puget Energy, Inc., as Borrower, JPMorgan Chaseborrower, Mizuho Bank N.A., as Administrative Agent and the lenders party thereto. (incorporated by reference to Exhibits 10.1 to Puget Energy's Current Report on Form 8-K, filed in October 31, 2017, Commission File No. 1-16305).Mizuho Bank, U.S. Bank and Co-Bank as lenders.
10.210.2*
Credit AgreementEmployment Offer Letter, dated October 25, 2017 amongas of June 20, 2019, by and between Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2017, Commission file No. 1-4393).
12.1*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016 and 12 months end September 30, 2017).
12.2*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2012 through 2016 and 12 months ended September 30, 2017).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.
31.2*
Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*
Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*
Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101
Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended September 30, 20172019 filed on November 3, 20176, 2019 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.



SIGNATURES

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

  
PUGET ENERGY, INC.
PUGET SOUND ENERGY, INC.
  
 
/s/ Stephen King
  
Stephen King
Controller & Principal Accounting Officer
Date:  November 3, 20176, 2019 



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