UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June 30, 2018~~March 31, 2019



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from ________ to ________



Commission File Number	Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number	I.R.S. Employer Identification Number



1-16305	PUGET ENERGY, INC. A Washington Corporation ~~10885~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-1969407



1-4393	PUGET SOUND ENERGY, INC. A Washington Corporation ~~10885~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-0374630

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 ~~interactive~~Interactive 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 ~~definition~~the 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 Information	5

Item 1.	Financial Statements	5
	Puget Energy, Inc.
	Consolidated Statements of Income – Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2018 and ~~2017~~2018	5
	Consolidated Statements of Comprehensive Income – Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	6
	Consolidated Balance Sheets – ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	7
	Consolidated Statements of ~~Cash Flows –~~ ~~Six Months Ended June 30, 2018~~Common Shareholder's Equity - March 31, 2019 and ~~2017~~December 31, 2018	8
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2019 and 2018	9

	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	910
	Consolidated Statements of Comprehensive Income – Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~	1011
	Consolidated Balance Sheets – ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018	1112
	Consolidated Statements of Common Shareholder's Equity - March 31, 2019 and December 31, 2018	14
	Consolidated Statements of Cash Flows – ~~Six~~Three Months Ended ~~June~~March 30, ~~2018~~2019 and ~~2017~~2018	1315

	Notes
	Combined Notes to Consolidated Financial Statements	1416

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3335

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	5954

Item 4.	Controls and Procedures	60

Part II.	Other Information	6155

Item 1.	Legal Proceedings	6155

Item 1A.	Risk Factors	6155

Item 6.	Exhibits	6155

Exhibit Index		6256

Signatures		6357

DEFINITIONS



ARO	Asset Retirement and Environmental Obligations
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EIM	Energy Imbalance Market
ERF	Expedited Rate Filing
FASB	Financial Accounting Standards Board
GAAP	U.S. Generally Accepted Accounting Principles
GRC	General Rate Case
ISDA	International Swaps and Derivatives Association
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
MMBtu	One Million British Thermal Units
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NPNS	Normal Purchase Normal Sale
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PTC	Production Tax Credit
PSE	Puget Sound Energy, Inc.
Puget Energy	Puget Energy, Inc.
Puget Holdings	Puget Holdings, LLC
Puget LNG	Puget Liquid Natural Gas, LLC
REP	Residential Exchange Program
SERP	Supplemental Executive Retirement Plan
TCJA	Tax Cuts and Jobs Act
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.

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 for the year ended December 31, ~~2017.~~2018.

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Electric	$	501,510		$	529,807		$	1,201,196		$	1,198,792		$	798,928		$	699,686
Natural gas	160,196			180,105			490,480			580,169			304,668			330,284
Other	10,146			9,855			18,184			18,038			11,243			8,038
Total operating revenue	671,852			719,767			1,709,860			1,796,999			1,114,839			1,038,008
Operating expenses:
Energy costs:
Purchased electricity	129,114			129,799			283,320			309,381			270,702			154,206
Electric generation fuel	29,750			34,163			72,173			85,473			77,199			42,423
Residential exchange	(16,091		)	(15,121		)	(40,035		)	(38,568		)	(25,163		)	(23,943		)
Purchased natural gas	53,872			63,183			181,487			215,984			99,387			127,615
Unrealized (gain) loss on derivative instruments, net	(6,911		)	3,834			(7,907		)	23,121			(15,187		)	(996		)
Utility operations and maintenance	140,131			145,555			300,655			297,618			157,955			160,524
Non-utility expense and other	8,419			6,144			21,249			11,339			13,757			12,830
Depreciation and amortization	152,105			119,457			336,617			234,710			180,697			184,512
Conservation amortization	24,025			25,691			60,888			60,453			33,286			36,864
Taxes other than income taxes	73,347			77,032			184,535			195,731			108,746			111,188
Total operating expenses	587,761			589,737			1,392,982			1,395,242			901,379			805,223
Operating income (loss)	84,091			130,030			316,878			401,757			213,460			232,785
Other income (expense):
Other income	8,116			6,263			21,573			12,223			13,564			13,455
Other expense	(2,330		)	(2,042		)	(4,428		)	(3,257		)	(1,776		)	(2,098		)
Non-hedged interest rate swap (expense) income	—			—			—			28
Interest charges:
AFUDC	3,318			2,555			6,201			4,730			3,350			2,884
Interest expense	(86,084		)	(88,409		)	(174,410		)	(176,991		)	(88,016		)	(88,326		)
Income (loss) before income taxes	7,111			48,397			165,814			238,490			140,582			158,700
Income tax (benefit) expense	3,469			13,122			15,272			75,665			8,428			11,803
Net income (loss)	$	3,642		$	35,275		$	150,542		$	162,825		$	132,154		$	146,897

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 June 30,					Six Months Ended June 30,					Three Months Ended March 31,
	2018		2017			2018			2017		2019		2018
Net income (loss)	$	3,642	$	35,275		$	150,542		162,825		$	132,154	$	146,897
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $60, $(115), $120, and $359, respectively	227		(214		)	453			666
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $25 and $60, respectively											92		227
Reclassification of stranded taxes to retained earnings due to tax reform	—		—			(5,230		)	—		—		(5,230		)
Other comprehensive income (loss)	227		(214		)	(4,777		)	666		92		(5,003		)
Comprehensive income (loss)	$	3,869	$	35,061		$	145,765		$	163,491	$	132,246	$	141,894

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

	June 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
Utility plant (at original cost, including construction work in progress of $637,322 and $495,937, respectively):
Utility plant (at original cost, including construction work in progress of $552,670 and $550,466 respectively):
Electric plant	$	8,305,168		$	8,135,847		$	8,594,886		$	8,515,482
Natural gas plant	3,444,954			3,307,545			3,665,783			3,598,732
Common plant	905,018			811,815			1,035,356			1,027,023
Less: Accumulated depreciation and amortization	(2,623,659		)	(2,428,524		)	(2,929,245		)	(2,832,321		)
Net utility plant	10,031,481			9,826,683			10,366,780			10,308,916
Other property and investments:
Goodwill	1,656,513			1,656,513			1,656,513			1,656,513
Other property and investments	222,170			182,355			256,708			244,444
Total other property and investments	1,878,683			1,838,868			1,913,221			1,900,957
Current assets:
Cash and cash equivalents	8,117			26,616			20,818			37,521
Restricted cash	10,083			10,145			42,221			18,041
Accounts receivable, net of allowance for doubtful accounts of $10,716 and $8,901, respectively	218,306			341,110
Accounts receivable, net of allowance for doubtful accounts of $10,358 and $8,408, respectively							415,725			338,782
Unbilled revenue	123,214			222,186			176,440			205,285
Purchased gas adjustment receivable							137,092			9,921
Materials and supplies, at average cost	112,913			107,003			120,243			116,180
Fuel and natural gas inventory, at average cost	51,084			49,908			40,161			53,351
Unrealized gain on derivative instruments	19,872			22,247			52,910			46,507
Prepaid expense and other	23,418			21,996			31,638			25,674
Power contract acquisition adjustment gain	8,480			12,207			6,888			6,114
Total current assets	575,487			813,418			1,044,136			857,376
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651			4,576			19,123			4,735
Regulatory assets related to power contracts	17,754			19,454			16,267			16,693
Other regulatory assets	818,081			948,532			688,072			773,552
Unrealized gain on derivative instruments	3,589			2,158			4,725			2,512
Power contract acquisition adjustment gain	159,168			162,711			154,629			156,597
Operating lease right of use asset							169,114			—
Other	84,159			74,389			78,909			77,523
Total other long-term and regulatory assets	1,087,402			1,211,820			1,130,839			1,031,612
Total assets	$	13,573,053		$	13,690,789		$	14,454,976		$	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

	June 30, 2018			December 31, 2017			March 31, 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 capital	3,308,957			3,308,957			3,308,957			3,308,957
Retained earnings	565,600			465,355			725,163			629,003
Accumulated other comprehensive income (loss), net of tax	(29,059		)	(24,282		)	(77,110		)	(77,202		)
Total common shareholder’s equity	3,845,498			3,750,030			3,957,010			3,860,758
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,164,412			3,764,412			3,764,412
Pollution control bonds	161,860			161,860			161,860			161,860
Junior subordinated notes	—			250,000
Long-term debt	1,939,551			1,902,600			1,975,300			1,961,900
Debt discount, issuance costs and other	(220,632		)	(220,943		)	(212,661		)	(215,681		)
Total long-term debt	5,645,191			5,257,929			5,688,911			5,672,491
Total capitalization	9,490,689			9,007,959			9,645,921			9,533,249
Current liabilities:
Accounts payable	308,305			359,586			505,623			480,069
Short-term debt	28,000			329,463			432,000			379,297
Current maturities of long-term debt	—			200,000
Purchased gas adjustment payable	38,645			16,051
Accrued expenses:
Taxes	104,092			117,948			129,252			118,112
Salaries and wages	42,180			53,220			32,170			50,785
Interest	69,564			73,564			80,196			70,099
Unrealized loss on derivative instruments	49,776			64,859			32,452			46,661
Power contract acquisition adjustment loss	2,585			2,762			2,537			2,547
Operating lease liabilities							13,876			—
Other	93,900			80,206			109,504			79,312
Total current liabilities	737,047			1,297,659			1,337,610			1,226,882
Other long-term and regulatory liabilities:
Deferred income taxes	774,195			746,868			809,799			789,297
Unrealized loss on derivative instruments	15,123			21,235			7,184			11,095
Regulatory liabilities	743,766			731,587			756,339			747,203
Regulatory liability for deferred income taxes	994,987			1,011,626			966,898			975,974
Regulatory liabilities related to power contracts	167,647			174,918			161,517			162,711
Power contract acquisition adjustment loss	15,169			16,693			13,730			14,146
Operating lease liabilities							160,786			—
Other deferred credits	634,430			682,244			595,192			638,304
Total other long-term and regulatory liabilities	3,345,317			3,385,171			3,471,445			3,338,730
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	13,573,053		$	13,690,789		$	14,454,976		$	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)

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Six Months Ended June 30,
2018 2017
Operating activities:
Net income (loss) $ 150,542
$ 162,825
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization 336,617
234,710
Conservation amortization 60,888
60,453
Deferred income taxes and tax credits, net 10,567
75,665
Net unrealized (gain) loss on derivative instruments (7,907 ) 22,980
AFUDC – equity (7,146 ) (6,766 )
Production tax credit monetization (51,181 ) —
Other non-cash 7,377
8,283
Funding of pension liability (9,000 ) (18,000 )
Regulatory assets and liabilities 4,591
(46,101 )
Other long-term assets and liabilities (12,611 ) 4,281
Change in certain current assets and liabilities:

Accounts receivable and unbilled revenue 220,207
196,179
Materials and supplies (5,910 ) 5,606
Fuel and natural gas inventory (1,176 ) 2,473
Prepayments and other (1,422 ) 13,900
Purchased gas adjustment 22,594
13,765
Accounts payable (47,040 ) (49,478 )
Taxes payable (13,856 ) (9,296 )
Other (16,937 ) (5,809 )
Net cash provided by (used in) operating activities 639,197
665,670
Investing activities:

Construction expenditures – excluding equity AFUDC (490,623 ) (496,652 )
Other 1,956
(6,642 )
Net cash provided by (used in) investing activities (488,667 ) (503,294 )
Financing activities:

Change in short-term debt, net (301,463 ) (240,763 )
Dividends paid (55,525 ) (132 )
Proceeds from long-term debt and bonds issued 631,701
48,073
Redemption of bonds and notes (450,000 ) —
Other 6,196
9,003
Net cash provided by (used in) financing activities (169,091 ) (183,819 )
Net increase (decrease) in cash, cash equivalents, and restricted cash (18,561 ) (21,443 )
Cash, cash equivalents, and restricted cash at beginning of period 36,761
41,296
Cash, cash equivalents, and restricted cash at end of period $ 18,200
$ 19,853
Supplemental cash flow information:

Cash payments for interest (net of capitalized interest) $ 164,823
$ 163,228
Cash payments (refunds) for income taxes 5,169
—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows $ 97,614
$ 54,419



	Common Stock			Additional					Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings			Comprehensive Income (Loss)			Total Equity
Balance at December 31, 2017	200	$	—	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, 2018	200	$	—	3,308,957		$	587,386		$	(29,285	)	$	3,867,058
Balance at December 31, 2018	200	$	—	$	3,308,957	$	629,003		$	(77,202	)	$	3,860,758
Net income (loss)	—	—		—		132,154			—			132,154
Common stock dividend paid	—	—		—		(35,994		)	—			(35,994		)
Other comprehensive income (loss)	—	—		—		—			92			92
Balance at March 31, 2019	200	$	—	$	3,308,957	$	725,163		$	(77,110	)	$	3,957,010

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

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

	Three Months Ended March 31,
	2019			2018
Operating activities:
Net income (loss)	$	132,154		$	146,897
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	180,697			184,512
Conservation amortization	33,286			36,864
Deferred income taxes and tax credits, net	11,401			14,517
Net unrealized (gain) loss on derivative instruments	(15,187		)	(996		)
AFUDC – equity	(3,597		)	(3,351		)
Production tax credit monetization	(27,131		)	(43,586		)
Other non-cash	3,722			3,720
Funding of pension liability	—			(4,500		)
Regulatory assets and liabilities	(15,838		)	20,871
Other long-term assets and liabilities	(13,463		)	(13,160		)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(24,413		)	49,476
Materials and supplies	(4,063		)	(1,825		)
Fuel and natural gas inventory	13,190			15,543
Prepayments and other	(5,964		)	(1,503		)
Purchased gas adjustment	(127,171		)	17,612
Accounts payable	45,827			(27,973		)
Taxes payable	11,140			19,614
Other	3,607			(13,411		)
Net cash provided by (used in) operating activities	198,197			399,321
Investing activities:
Construction expenditures – excluding equity AFUDC	(227,807		)	(241,181		)
Other	264			1,570
Net cash provided by (used in) investing activities	(227,543		)	(239,611		)
Financing activities:
Change in short-term debt, net	52,703			41,226
Dividends paid	(35,994		)	(30,096		)
Proceeds from long-term debt and bonds issued	13,400			13,179
Redemption of bonds and notes	—			(193,447		)
Other	6,714			(1,530		)
Net cash provided by (used in) financing activities	36,823			(170,668		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	7,477			(10,958		)
Cash, cash equivalents, and restricted cash at beginning of period	55,562			36,761
Cash, cash equivalents, and restricted cash at end of period	$	63,039		$	25,803
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	46,036		$	81,736
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	77,400		$	90,169

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 June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Operating revenue:
Electric	$	501,510		$	529,807		$	1,201,196		$	1,198,792		$	798,928		$	699,686
Natural gas	160,196			180,105			490,480			580,169			304,668			330,284
Other	10,146			9,855			18,184			18,038			11,243			8,038
Total operating revenue	671,852			719,767			1,709,860			1,796,999			1,114,839			1,038,008
Operating expenses:
Energy costs:
Purchased electricity	129,114			129,799			283,320			309,381			270,702			154,206
Electric generation fuel	29,750			34,163			72,173			85,473			77,199			42,423
Residential exchange	(16,091		)	(15,121		)	(40,035		)	(38,568		)	(25,163		)	(23,943		)
Purchased natural gas	53,872			63,183			181,487			215,984			99,387			127,615
Unrealized (gain) loss on derivative instruments, net	(6,911		)	3,834			(7,907		)	23,121			(15,187		)	(996		)
Utility operations and maintenance	140,131			145,555			300,655			297,618			157,955			160,524
Non-utility expense and other	10,834			9,374			20,614			17,865			13,077			9,781
Depreciation and amortization	152,080			119,457			336,570			234,710			180,678			184,490
Conservation amortization	24,025			25,691			60,888			60,453			33,286			36,864
Taxes other than income taxes	73,347			77,032			184,535			195,731			108,746			111,188
Total operating expenses	590,151			592,967			1,392,300			1,401,768			900,680			802,152
Operating income (loss)	81,701			126,800			317,560			395,231			214,159			235,856
Other income (expense):
Other income	8,113			6,126			15,756			12,086			10,549			7,641
Other expense	(2,330		)	(2,042		)	(4,428		)	(3,257		)	(1,776		)	(2,098		)
Interest charges:
AFUDC	3,318			2,555			6,201			4,730			3,350			2,884
Interest expense	(57,020		)	(59,991		)	(116,575		)	(120,453		)	(60,150		)	(59,555		)
Income (loss) before income taxes	33,782			73,448			218,514			288,337			166,132			184,728
Income tax (benefit) expense	7,004			22,794			28,696			94,591			18,830			21,691
Net income (loss)	$	26,778		$	50,654		$	189,818		$	193,746		$	147,302		$	163,037

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 June 30,				Six Months Ended June 30,					Three Months Ended March 31,
	2018		2017		2018			2017		2019		2018
Net income (loss)	$	26,778	$	50,654	$	189,818		$	193,746	$	147,302	$	163,037
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $761, $1,143, $1,522, and $2,875, respectively	2,863		2,123		5,727			5,339
Amortization of treasury interest rate swaps to earnings, net of tax of $26, $43, $51, and $86, respectively	96		79		192			158
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $668 and $761, respectively										2,510		2,863
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $26, respectively										96		96
Reclassification of stranded taxes to retained earnings due to tax reform	—		—		(27,333		)	—		—		(27,333		)
Other comprehensive income (loss)	2,959		2,202		(21,414		)	5,497		2,606		(24,374		)
Comprehensive income (loss)	$	29,737	$	52,856	$	168,404		$	199,243	$	149,908	$	138,663

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS


	June 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
Utility plant (at original cost, including construction work in progress of $637,322 and $495,937, respectively):
Utility plant (at original cost, including construction work in progress of $552,670 and $550,466 respectively):
Electric plant	$	10,389,267		$	10,232,771		$	10,663,316		$	10,587,231
Natural gas plant	4,018,260			3,882,733			4,230,411			4,164,489
Common plant	935,706			843,145			1,060,623			1,052,544
Less: Accumulated depreciation and amortization	(5,311,752		)	(5,131,966		)	(5,587,570		)	(5,495,348		)
Net utility plant	10,031,481			9,826,683			10,366,780			10,308,916
Other property and investments:
Other property and investments	77,109			76,350			79,128			76,986
Total other property and investments	77,109			76,350			79,128			76,986
Current assets:
Cash and cash equivalents	7,104			25,864			19,948			35,452
Restricted cash	10,083			10,145			42,221			18,041
Accounts receivable, net of allowance for doubtful accounts of $10,716 and $8,901, respectively	224,901			343,546
Accounts receivable, net of allowance for doubtful accounts of $10,358 and $8,408, respectively							418,492			346,251
Unbilled revenue	123,214			222,186			176,440			205,285
Purchased gas adjustment receivable							137,092			9,921
Materials and supplies, at average cost	112,913			107,003			120,243			116,180
Fuel and natural gas inventory, at average cost	49,761			48,585			38,838			52,028
Unrealized gain on derivative instruments	19,872			22,247			52,910			46,507
Prepaid expense and other	23,418			21,996			31,638			25,674
Total current assets	571,266			801,572			1,037,822			855,339
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651			4,576			19,123			4,735
Other regulatory assets	818,081			948,540			688,072			773,552
Unrealized gain on derivative instruments	3,589			2,158			4,725			2,512
Operating lease right of use asset							169,114			—
Other	81,862			71,827			77,002			75,483
Total other long-term and regulatory assets	908,183			1,027,101			958,036			856,282
Total assets	$	11,588,039		$	11,731,706		$	12,441,766		$	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


	June 30, 2018			December 31, 2017			March 31, 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 capital	3,275,105			3,275,105			3,275,105			3,275,105
Retained earnings	566,758			452,066			705,542			622,844
Accumulated other comprehensive income (loss), net of tax	(148,320		)	(126,906		)	(188,278		)	(190,884		)
Total common shareholder’s equity	3,694,402			3,601,124			3,793,228			3,707,924
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,164,412			3,764,412			3,764,417
Pollution control bonds	161,860			161,860			161,860			161,860
Junior subordinated notes	—			250,000
Debt discount, issuance costs and other	(31,230		)	(26,361		)	(31,007		)	(31,417		)
Total long-term debt	3,895,042			3,549,911			3,895,265			3,894,860
Total capitalization	7,589,444			7,151,035			7,688,493			7,602,784
Current liabilities:
Accounts payable	308,304			359,585			505,636			480,195
Short-term debt	28,000			329,463			432,000			379,297
Current maturities of long-term debt	—			200,000
Purchased gas adjustment payable	38,645			16,051
Accrued expenses:
Taxes	104,092			117,063			131,643			117,993
Salaries and wages	42,180			53,220			32,170			50,785
Interest	43,672			47,837			56,903			43,951
Unrealized loss on derivative instruments	49,776			64,859			32,452			46,661
Operating lease liabilities							13,876			—
Other	93,900			80,206			109,504			79,312
Total current liabilities	708,569			1,268,284			1,314,184			1,198,194
Other long-term and regulatory liabilities:
Deferred income taxes	906,226			869,473			955,277			926,403
Unrealized loss on derivative instruments	15,123			21,235			7,184			11,095
Regulatory liabilities	742,443			730,273			755,016			745,880
Regulatory liability for deferred income taxes	995,599			1,012,260			967,694			976,582
Operating lease liabilities							160,786			—
Other deferred credits	630,635			679,146			593,132			636,585
Total other long-term and regulatory liabilities	3,290,026			3,312,387			3,439,089			3,296,545
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	11,588,039		$	11,731,706		$	12,441,766		$	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)



	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	—	—		—		(58,611		)	—			(58,611		)
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	$	583,825		$	(151,280	)	$	3,708,509
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

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)


	Six Months Ended June 30,						Three Months Ended March 31,
	2018			2017			2019			2018
Operating activities:
Net income (loss)	$	189,818		$	193,746		$	147,302		$	163,037
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	336,570			234,710			180,678			184,490
Conservation amortization	60,888			60,453			33,286			36,864
Deferred income taxes and tax credits, net	18,519			94,590			19,293			19,505
Net unrealized (gain) loss on derivative instruments	(7,907		)	23,121			(15,187		)	(996		)
AFUDC – equity	(7,146		)	(6,766		)	(3,597		)	(3,351		)
Production tax credit monetization	(51,181		)	—			(27,131		)	(43,586		)
Other non-cash	2,197			2,675			1,109			1,131
Funding of pension liability	(9,000		)	(18,000		)	—			(4,500		)
Regulatory assets and liabilities	4,591			(46,101		)	(15,838		)	20,871
Other long-term assets and liabilities	(5,956		)	(14,507		)	(11,959		)	(9,844		)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	216,047			205,327			(19,711		)	41,558
Materials and supplies	(5,910		)	5,606			(4,063		)	(1,825		)
Fuel and natural gas inventory	(1,176		)	2,473			13,190			15,543
Prepayments and other	(1,422		)	13,900			(5,964		)	(1,503		)
Purchased gas adjustment	22,594			13,765			(127,171		)	17,612
Accounts payable	(47,040		)	(49,478		)	45,714			(27,973		)
Taxes payable	(12,971		)	(9,296		)	13,650			24,515
Other	(17,100		)	(6,542		)	8,006			(10,694		)
Net cash provided by (used in) operating activities	684,415			699,676			231,607			420,854
Investing activities:
Construction expenditures – excluding equity AFUDC	(452,220		)	(431,536		)	(218,006		)	(221,099		)
Other	1,956			(6,205		)	264			1,570
Net cash provided by (used in) investing activities	(450,264		)	(437,741		)	(217,742		)	(219,529		)
Financing activities:
Change in short-term debt, net	(301,463		)	(240,763		)	52,703			41,226
Dividends paid	(102,456		)	(51,574		)	(64,604		)	(58,611		)
Long-term bonds and notes issued	594,750			—
Redemption of bonds and notes	(450,000		)	—			—			(193,447		)
Other	6,196			9,003			6,712			(1,529		)
Net cash provided by (used in) financing activities	(252,973		)	(283,334		)	(5,189		)	(212,361		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(18,822		)	(21,399		)	8,676			(11,036		)
Cash, cash equivalents, and restricted cash at beginning of period	36,009			40,899			53,493			36,009
Cash, cash equivalents, and restricted cash at end of period	$	17,187		$	19,500		$	62,169		$	24,973
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	112,354		$	112,801		$	43,181		$	52,847
Cash payments (refunds) for income taxes	$	9,631		$	—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	97,614		$	54,419		$	77,400		$	90,169

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, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma ~~LNG~~liquefied natural gas (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 under~~are incurred by PSE and ~~are~~ allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As ~~of June 30, 2018, Puget LNG has incurred $145.5 million in construction work in progress and operating costs related to Puget LNG’s portion~~a result of the ~~Tacoma LNG facility.~~ merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Tacoma LNG Facility

The Tacoma LNG facility is intended to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) is necessary in order to rule on the air quality permit for the facility. As a result of requiring a ~~Supplemental Environmental Impact Statement,~~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 draft SEIS on March 29, 2019 which concluded the LNG facility would 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 adversely impacted. Pursuant to an order by the Washington Utilities and Transportation Commission (Washington Commission), PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

~~For Puget Energy, $144.7~~ Per this allocation of costs, $175.7 million inof construction work in progress and $0.3 million of operating costs related to Puget ~~LNG’s~~LNG's portion of the Tacoma LNG facility isare reported in the ~~“Other~~Puget Energy "Other property and ~~investments”~~investments" and "Non-utility expense and other" financial statement line ~~item. For PSE,~~items, respectively, as of March 31, 2019. Additionally, $139.7 million of construction work in progress ~~of $113.4 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 lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. 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 operating lease ROU asset also includes any lease payments made and excludes lease incentives. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.

PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

(2) New Accounting Pronouncements

Recently Adopted Accounting Guidance

~~Income Taxes~~

~~In March 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-05,~~ ~~"Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118"~~. The staff of the U.S. Securities and Exchange Commission (SEC) recognized the complexity of reflecting the impacts of the Tax Cuts Job Act (TCJA), and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (SAB 118), which clarifies accounting for income taxes under Accounting Standards Codification (ASC) 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysis and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (i) a company is complete with its accounting for certain effects of tax reform, (ii) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (iii) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and has made a reasonable estimate as to the other effects and has reflected the measurement and accounting

of the effects in the consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. The Company has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to the Company's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. At December 31, 2017, the Company did not identify any effects of the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate. Additionally, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for impacts of tax reform. For additional information, see Note 7, "Regulation and Rates" to the consolidated financial statements included in Item 1 of this report.

~~Stranded Tax Effects in AOCI~~

~~In February 2018, the FASB issued ASU 2018-02, "Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income~~". The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users.

This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company early adopted ASU 2018-02 as of January 1, 2018 with a reclassification from accumulated other comprehensive income to retained earnings in the amount of a $5.2 million increase for Puget Energy related to pension and post-retirement plans and a $27.3 million increase for PSE, comprised of $26.2 million related to pension and post-retirement plans, and $1.1 million related to interest rate swaps.

~~Retirement Benefits~~

~~In March 2017, the FASB issued ASU 2017-07, "Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.~~" The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization.

This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company adopted ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. For additional information, see Note 6, "Retirement Benefits" to the consolidated financial statements included in Item 1 of this report.

~~Statement of Cash Flows~~

~~In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments~~". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle.

This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-15 as of January 1, 2018 with the standard only impacting the classification of debt extinguishment costs as financing outflows.

~~In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash~~". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company has adopted ASU 2016-18 as of January 1, 2018 by moving the presentation of restricted cash in the statement of cash flows to net cash flows of total cash, cash equivalents, and restricted cash. Amounts included in restricted cash primarily represent funds required to be set aside for contractual obligations related to transmission and generation facilities.

~~The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the statements of cash flows:~~

Puget Energy Six Months Ended
June 30,
(Dollars in Thousands) 2018 2017
Cash and cash equivalents $ 8,117
$ 7,805
Restricted cash 10,083
12,048
Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 18,200
$ 19,853

Puget Sound Energy Six Months Ended
June 30,
(Dollars in Thousands) 2018 2017
Cash and cash equivalents $ 7,104
$ 7,452
Restricted cash 10,083
12,048
Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 17,187
$ 19,500

~~Revenue Recognition~~

~~In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)~~". Accounting Standards Update (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. The 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.

The Company implemented the standard as of January 1, 2018 using the modified retrospective method of adoption. As a result of implementation of this standard, the Company made no cumulative adjustments to revenue for contracts with customers open as of January 1, 2018. For the three and six months ended June 30, 2018, the Company's revenue was 93.3% and 93.1% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue is recognized over time as delivered. Pursuant to the new standard, the Company has added enhanced quantitative and qualitative disclosure for revenue from contracts with customers and revenue outside the scope of the standard, in Note 3, "Revenue" to the consolidated financial statements included in Item 1 of this report.

~~Accounting Standards Issued but Not Yet Adopted~~

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB ~~Accounting Standards Codification~~ASC and creating 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-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842". In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current ~~leases~~ 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 plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019.

~~This amendment is~~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 adopt~~has adopted ASU 2016-02 ~~during~~as 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 ~~assets~~asset and ~~liabilities~~lease liability financial statement line items that have not previously been recorded ~~which will~~and are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the income statement. The financial impact as of the date of adoption was not materially different than what has been disclosed as of March 31, 2019, in Note 9, "Leases", to the consolidated ~~balance sheets.~~financial statements included in Item 1 of this report.

Internal-Use Software

In August 2018, the FASB issued ASU 2018-15, "Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract". These amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The accounting for the service element of a hosting arrangement that is a service contract is not affected by these amendments.

The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted, including adoption in any interim period, for all entities. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company adopted this update prospectively in 2019 for implementation costs incurred in hosting arrangements.

Accounting Standards Issued but Not Yet Adopted

Credit Losses

In June 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326). The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 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 in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company is in the 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 June 30,			Six Months Ended June 30,			Three Months Ended March 31,
Revenue from contracts with customers:	2018			2018			2019			2018
Electric retail	$	468,378		$	1,099,184		$	637,189		$	630,806
Natural gas retail	158,544			492,578			322,560			334,033
Other	38,930			81,364			135,696			42,434
Total revenue from contracts with customers	665,852			1,673,126			1,095,445			1,007,273
Alternative revenue programs	(8,815		)	(23,897		)	(25,231		)	(15,081		)
Other non-customer revenue	14,815			60,631			44,625			45,816
Total operating revenue	$	671,852		$	1,709,860		$	1,114,839		$	1,038,008

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~~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, as the~~revenue. The obligation of standing ready to perform electric service and ~~for~~ 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 ~~Utility and Transportation~~ Commission ~~(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 ~~Federal Energy Regulatory Commission (FERC)~~FERC and, therefore, corresponds directly to the value to the customer for performance completed to date.

Biogas Revenue

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

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

Wholesale Revenue

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

Other Revenue

In accordance with ASC 606, PSE ~~excludes~~separately presents revenue not collected from contracts with customers ~~as well as revenue~~ that falls under other accounting guidance.

(4) Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs.

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings.

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts.

The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets:


Puget Energy and Puget Sound Energy
	At June 30, 2018					At December 31, 2017					At March 31, 2019					December 31, 2018
(Dollars in Thousands)	Volumes	Assets¹		Liabilities²		Volumes	Assets¹		Liabilities²		Volumes	Assets¹		Liabilities²		Volumes	Assets¹		Liabilities²
Electric portfolio derivatives	*	$	10,889	$	38,642	*	$	13,391	$	49,050	*	$	37,728	$	16,538	*	$	33,287	$	27,284
Natural gas derivatives (MMBtus)³	299.2 million	12,572		26,257		332.1 million	11,014		37,044		316.3 million	19,907		23,098		336.6 million	15,732		30,472
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094		$	57,635	$	39,636		$	49,019	$	57,756
Current		$	19,872	$	49,776		$	22,247	$	64,859		$	52,910	$	32,452		$	46,507	$	46,661
Long-term		3,589		15,123			2,158		21,235			4,725		7,184			2,512		11,095
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094		$	57,635	$	39,636		$	49,019	$	57,756

_______________


¹	Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.


²	Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.

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 ~~172.5~~199.9 million One Million British Thermal Units (MMBtu) and purchased electricity of ~~3.7~~10.1 million Megawatt Hours (MWhs) at ~~June 30, 2018,~~March 31, 2019, and ~~166.8~~194.8 million MMBtus and ~~2.9~~6.6 million MWhs at December 31, ~~2017.~~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 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report.

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy														Puget Energy and Puget Sound Energy
	At June 30, 2018														At March 31, 2019
	Gross Amount Recognized in the Statement of Financial Position¹		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position								Gross Amount Recognized in the Statement of Financial Position¹		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted			Net Amount								Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	23,461	$	—	$	23,461	$	(17,120	)	$	—		$	6,341	$	57,635	$	—	$	57,635	$	(29,907	)	$	—	$	27,728
Liabilities:
Energy derivative contracts	64,899		—		64,899		(17,120		)	(1,220		)	46,559		39,636		—		39,636		(29,907		)	—		9,729


Puget Energy and Puget Sound Energy	Puget Energy and Puget Sound Energy														Puget Energy and Puget Sound Energy
	At December 31, 2017														At December 31, 2018
	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 Contracts			Cash Collateral Received/Posted			Net Amount								Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465	$	49,019	$	—	$	49,019	$	(25,388	)	$	—	$	23,631
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801		57,756		—		57,756		(25,388		)	—		32,368

_______________


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

The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy and
Puget Sound Energy Three Months Ended
June 30, Six Months Ended
June 30,
(Dollars in Thousands) Classification 2018 2017 2018 2017
Interest rate contracts¹:

Non-hedged interest rate swap
(expense) income
$ —
$ —
$ —
$ 28
Gas for Power Derivatives:

Unrealized Unrealized gain (loss) on derivative instruments, net 5,357
(5,746 ) 7,669
(21,882 )
Realized Electric generation fuel (4,417 ) (2,822 ) (12,093 ) (8,020 )
Power Derivatives:
Unrealized Unrealized gain (loss) on derivative instruments, net 1,554
1,912
238
(1,239 )
Realized Purchased electricity (2,836 ) (3,923 ) (5,225 ) (10,078 )
Total gain (loss) recognized in income on derivatives $ (342 ) $ (10,579 ) $ (9,411 ) $ (41,191 )

~~_______________~~

¹~~Interest rate swap contracts were held at Puget Energy, and matured January 2017.~~



Puget Energy and Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	Classification	2019		2018
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	14,961		2,312
Realized	Electric generation fuel	13,328		(7,676		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	226		(1,316		)
Realized	Purchased electricity	36,292		(2,389		)
Total gain (loss) recognized in income on derivatives		$	64,807	$	(9,069	)

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation.

The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of ~~June 30, 2018,~~March 31, 2019, approximately ~~94.6%~~95.6% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, ~~was~~is with counterparties that are rated investment grade by rating agencies and ~~5.4%~~4.4% 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 June 30, 2018, 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. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE) ~~platform, which~~, and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of ~~June 30, 2018,~~March 31, 2019, PSE had cash posted as collateral of ~~$3.7~~$20.3 million related to contracts executed on ~~this~~the ICE platform. ~~As additional contracts are executed on this exchange, the amount~~Also, as of March 31, 2019, PSE had $12.3 million in cash collateral ~~to be posted will increase, subject to PSE’s established limit. PSE also has~~and 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 nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019.

The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post:


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30, 2018						At December 31, 2017						At March 31, 2019						At December 31, 2018
	Fair Value¹		Posted		Contingent		Fair Value¹		Posted		Contingent		Fair Value¹		Posted		Contingent		Fair Value¹		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral		Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating²	$	1,356	$	—	$	1,356	$	3,187	$	—	$	3,187	$	1,442	$	—	$	1,442	$	574	$	—	$	574
Requested credit for adequate assurance	25,805		—		—		37,374		—		—		5,175		—		—		18,495		—		—
Forward value of contract³	1,220		3,691		—		353		2,639		—
Total	$	28,381	$	3,691	$	1,356	$	40,914	$	2,639	$	3,187	$	6,617	$	—	$	1,442	$	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.~~


(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-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling ~~$49.1~~$49.6 million and ~~$48.5~~$49.5 million at ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017,~~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 June 30, 2018				At December 31, 2017					At March 31, 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 notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount¹	2	5,505,640		6,483,719		5,105,329		6,520,515		2	5,513,611		6,698,705		5,510,591		6,443,742
Long-term debt (variable-rate)	2	139,551		139,551		102,600		102,600		2	175,300		175,300		161,900		161,900
Total liabilities		$	5,645,191	$	6,623,270	$	5,457,929	$	6,862,050		$	5,688,911	$	6,874,005	$	5,672,491	$	6,605,642


Puget Sound Energy		At June 30, 2018				At December 31, 2017					At March 31, 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 notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount²	2	3,895,042		4,598,167		3,499,911		4,550,130		2	3,895,265		4,819,290		3,894,860		4,574,611
Total liabilities		$	3,895,042	$	4,598,167	$	3,749,911	$	4,789,065		$	3,895,265	$	4,819,290	$	3,894,860	$	4,574,611

_______________


¹	The carrying value includes debt issuances costs of ~~$26.6~~$25.3 million and ~~$27.9~~$26.1 million for ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively, which are not included in fair value.


²	The carrying value includes debt issuances costs of $24.2 million and $24.6 million for ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively, which are not included in fair value.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:


Puget Energy and	Fair Value						Fair Value						Fair Value						Fair Value
Puget Sound Energy	At June 30, 2018						At December 31, 2017						At March 31, 2019						At December 31, 2018
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total		Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,229	$	3,660	$	10,889	$	9,866	$	3,525	$	13,391	$	29,849	$	7,879	$	37,728	$	28,765	$	4,522	$	33,287
Natural gas derivative instruments	6,510		6,062		12,572		6,973		4,041		11,014		15,738		4,169		19,907		12,247		3,485		15,732
Total assets	$	13,739	$	9,722	$	23,461	$	16,839	$	7,566	$	24,405	$	45,587	$	12,048	$	57,635	$	41,012	$	8,007	$	49,019
Liabilities:
Electric derivative instruments	$	36,991	$	1,651	$	38,642	$	46,623	$	2,427	$	49,050	$	13,671	$	2,867	$	16,538	$	24,124	$	3,160	$	27,284
Natural gas derivative instruments	24,144		2,113		26,257		34,926		2,118		37,044		21,687		1,411		23,098		28,660		1,812		30,472
Total liabilities	$	61,135	$	3,764	$	64,899	$	81,549	$	4,545	$	86,094	$	35,358	$	4,278	$	39,636	$	52,784	$	4,972	$	57,756

The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:


Puget Energy and Puget Sound Energy	Three Months Ended June 30,
Puget Energy and																			Three Months Ended March 31,
Puget Sound Energy
(Dollars in Thousands)	2018									2017									2019									2018
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total			Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,186		$	5,096		$	6,282		$	3,788		$	1,752		$	5,540		$	1,362		$	1,673		$	3,035		$	1,098		$	1,923		$	3,021
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings¹	366			—			366			339			—			339			12,325			—			12,325			1,619			—			1,619
Included in regulatory assets / liabilities	—			354			354			—			1,124			1,124			—			1,897			1,897			—			4,976			4,976
Settlements	(151		)	(1,800		)	(1,951		)	(2,508		)	(1,974		)	(4,482		)	(13,483		)	(1,100		)	(14,583		)	(503		)	(1,803		)	(2,306		)
Transferred into Level 3	—			—			—			—			—			—			4,391			(398		)	3,993			(1,837		)	—			(1,837		)
Transferred out of Level 3	608			299			907			(976		)	554			(422		)	417			686			1,103			809			—			809
Balance at end of period	$	2,009		$	3,949		$	5,958		$	643		$	1,456		$	2,099		$	5,012		$	2,758		$	7,770		$	1,186		$	5,096		$	6,282

Puget Energy and
Puget Sound Energy
Six Months Ended June 30,
(Dollars in Thousands) 2018 2017
Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total
Balance at beginning of period $ 1,098
$ 1,923
$ 3,021
$ 972
$ 625
$ 1,597
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings²
1,985
—
1,985
1,045
—
1,045
Included in regulatory assets / liabilities —
5,329
5,329
—
3,582
3,582
Settlements (654 ) (3,602 ) (4,256 ) (3,838 ) (3,304 ) (7,142 )
Transferred into Level 3 (1,837 ) —
(1,837 ) 2,191
(553 ) 1,638
Transferred out of Level 3 1,417
299
1,716
273
1,106
1,379
Balance at end of period $ 2,009
$ 3,949
$ 5,958
$ 643
$ 1,456
$ 2,099

~~______________~~_______________


^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 ~~$0.7~~$3.1 million and ~~$0.5~~$2.0 million for the three months ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~, ~~respectively.~~


²	Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.7 million~~and $0.7 million for the six months ended June 30, 2018 and 2017,~~ 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 ~~June 30, 2018~~March 31, 2019:


Puget Energy and Puget Sound Energy	Fair Value						Range
Puget Energy and													Fair Value							Range
Puget Sound Energy													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	$	3,660	$	1,651	Discounted cash flow	Power prices (per MWh)	$	20.97	$	40.25	$	26.52	$	7,879	$	2,867	Discounted cash flow		Power prices (per MWh)	$	20.12		$	72.30		$	38.88
Natural gas	$	6,062	$	2,113	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.74	$	2.73	$	2.14	$	4,169	$	1,411	Discounted cash flow		Natural gas prices (per MMBtu)	$	0.72		$	3.79		$	2.71

_______________


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, ~~2017:~~2018:


Puget Energy and Puget Sound Energy	Fair Value						Range
Puget Energy and													Fair Value						Range
Puget Energy Sound													Fair Value
(Dollars in Thousands)	Assets¹		Liabilities¹		Valuation Technique	Unobservable Input	Low		High		Weighted Average		Assets¹		Liabilities¹		Valuation Technique	Unobservable Input	Range	Low		High		Weighted Average
Electric	$	3,525	$	2,427	Discounted cash flow	Power prices (per MWh)	$	7.02	$	28.94	$	18.61	$	4,522	$	3,160	Discounted cash flow	Power prices (per MWh)	$	11.35	$	66.45	$	29.63
Natural gas	$	4,041	$	2,118	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.22	$	2.80	$	1.54	$	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 ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, a hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by ~~$1.1~~$5.7 million and ~~$0.9~~$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 any~~recoverability whenever events or changes in circumstances indicate that ~~would~~its 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 ~~June 30, 2018,~~March 31, 2019, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. As of March 31, 2018, the Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017, causing an impairment of $1.9 million.

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

Puget Energy
(Dollars in Thousands)
Valuation Date Contract Name Carrying Value Fair Value Write Down
March 31, 2018 Wells Hydro $ 4,302
$ 2,395
$ 1,907

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 Date Unobservable Input Low High Average
March 31, 2018 Power prices (per MWh) $9.69 $25.30 $17.50
Power contract costs per quarter (in thousands) 4,126 4,126 4,126


(6)	Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering ~~the largest portion~~a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting January 1, 2014, all United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the ~~IBEW,~~International Brotherhood of Electrical Workers (IBEW), participants will receive annual ~~pay credits~~employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees ~~electing~~receiving contributions in the ~~defined benefits pension~~cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, ~~he or she~~they will have annuity and lump sum options for distribution. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. Puget Energy's retirement plans were re-measured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans.

In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. ~~The~~Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.

The following tables summarize the Company’s net periodic benefit cost for the three ~~and six~~ months ended ~~June 30, 2018~~March 31, 2019 and ~~2017:~~2018:


Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits						Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,																Three Months Ended March 31,
(Dollars in Thousands)	2018			2017			2018		2017		2018			2017			2019			2018			2019		2018		2019			2018
Components of net periodic benefit cost:
Service cost	$	5,425		$	5,023		$	212	$	228	$	17		$	16		$	5,287		$	5,425		$	256	$	212	$	16		$	17
Interest cost	6,780			7,088			530		571		110			130			7,216			6,780			578		530		112			110
Expected return on plan assets	(12,559		)	(11,942		)	—		—		(117		)	(116		)	(12,624		)	(12,559		)	—		—		(97		)	(117		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—			(495		)	(495		)	83		11		—			—
Amortization of net loss (gain)	462			—			394		269		(86		)	(88		)	251			462			341		394		(63		)	(86		)
Net periodic benefit cost	$	(387	)	$	(326	)	$	1,147	$	1,079	$	(76	)	$	(58	)	$	(365	)	$	(387	)	$	1,258	$	1,147	$	(32	)	$	(76	)

Puget Energy Qualified
Pension Benefits SERP
Pension Benefits Other
Benefits
Six Months Ended June 30,
(Dollars in Thousands) 2018 2017 2018 2017 2018 2017
Components of net periodic benefit cost:
Service cost $ 10,851
$ 10,040
$ 423
$ 457
$ 35
$ 36
Interest cost 13,560
14,186
1,060
1,143
220
250
Expected return on plan assets (25,119 ) (23,892 ) —
—
(235 ) (231 )
Amortization of prior service cost (990 ) (990 ) 22
22
—
—
Amortization of net loss (gain) 925
—
790
538
(172 ) (201 )
Net periodic benefit cost $ (773 ) $ (656 ) $ 2,295
$ 2,160
$ (152 ) $ (146 )

Puget Sound Energy
Qualified
Pension Benefits

SERP
Pension Benefits

Other
Benefits

Three Months Ended June 30,
(Dollars in Thousands) 2018 2017 2018 2017 2018 2017
Components of net periodic benefit cost:

Service cost $ 5,425
$ 5,023
$ 212
$ 228
$ 17
$ 16
Interest cost 6,780
7,088
530
571
110
130
Expected return on plan assets (12,569 ) (11,963 ) —
—
(117 ) (116 )
Amortization of prior service cost (393 ) (393 ) 11
11
—
—
Amortization of net loss (gain) 3,630
3,095
517
392
(142 ) (148 )
Net periodic benefit cost $ 2,873
$ 2,850
$ 1,270
$ 1,202
$ (132 ) $ (118 )

Puget Sound Energy Qualified
Pension Benefits SERP
Pension Benefits Other
Benefits
Six Months Ended June 30,
(Dollars in Thousands) 2018 2017 2018 2017 2018 2017
Components of net periodic benefit cost:
Service cost $ 10,851
$ 10,040
$ 423
$ 457
$ 35
$ 36
Interest cost 13,560
14,186
1,060
1,143
220
250
Expected return on plan assets (25,138 ) (23,931 ) —
—
(235 ) (231 )
Amortization of prior service cost (787 ) (787 ) 22
22
—
—
Amortization of net loss (gain) 7,260
6,524
1,035
783
(283 ) (320 )
Net periodic benefit cost $ 5,746
$ 6,032
$ 2,540
$ 2,405
$ (263 ) $ (265 )



Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended March 31,
(Dollars in Thousands)	2019			2018			2019		2018		2019			2018
Components of net periodic benefit cost:
Service cost	$	5,287		$	5,425		$	256	$	212	$	16		$	17
Interest cost	7,216			6,780			578		530		112			110
Expected return on plan assets	(12,628		)	(12,569		)	—		—		(98		)	(117		)
Amortization of prior service cost	(393		)	(393		)	83		11		—			—
Amortization of net loss (gain)	3,165			3,630			433		517		(109		)	(142		)
Net periodic benefit cost	$	2,647		$	2,873		$	1,350	$	1,270	$	(79	)	$	(132	)

The following table summarizes the Company’s change in benefit obligation for the periods ended ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017:~~2018:


Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits						Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018			March 31, 2019			December 31, 2018			March 31, 2019			December 31, 2018
Change in benefit obligation:
Benefit obligation at beginning of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194		$	677,643		$	700,481		$	55,708		$	55,754		$	10,636		$	11,454
Amendments																			—			—			—			1,446			—			—
Service cost	10,851			20,081			423			913			35			72			5,287			22,757			256			847			16			69
Interest cost	13,560			28,373			1,060			2,285			220			500			7,216			27,303			578			2,120			112			444
Actuarial loss (gain)	—			40,945			—			2,722			—			725			—			(29,067		)	—			1,122			—			(379		)
Benefits paid	(21,300		)	(40,594		)	(1,080		)	(1,900		)	(562		)	(1,137		)	(10,925		)	(42,662		)	(503		)	(5,581		)	(262		)	(1,037		)
Medicare part D subsidy received	—			—			—			—			85			100			—			—			—			—			—			85
Administrative Expense	—			(931		)	—			—			—			—			—			(1,169		)	—			—			—			—
Benefit obligation at end of period	$	703,592		$	700,481		$	56,157		$	55,754		$	11,232		$	11,454		$	679,221		$	677,643		$	56,039		$	55,708		$	10,502		$	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, ~~2018~~2019 are expected to be at least $18.0 million, ~~$5.5~~$6.2 million and ~~$0.3~~$0.2 million, respectively. During the three months ended ~~June 30,~~March 31, 2019, the Company contributed $0.5 million to fund the SERP. During the three months ended March 31, 2018, the Company contributed $4.5 million and $0.6 ~~million to fund the qualified pension plan and SERP, respectively. During the six months ended June 30, 2018, the Company contributed $9.0 million and $1.1~~ million to fund the qualified pension plan and SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plans.

(7) Regulation and Rates

~~General~~Expedited Rate ~~Case~~ Filing

~~In January 2017,~~On November 7, 2018, PSE filed ~~its general~~an expedited rate ~~case (GRC)~~filing (ERF) with the Washington Commission. The ~~GRC~~ filing ~~included~~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 ~~required plan~~Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to ~~address Colstrip Units 1~~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 ~~2 closures, requested~~an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contestedresolved all issues in the ~~case~~filing. The settlement agreement was filed on ~~December 5, 2017~~

January 30, 2019. The parties agreed to a $21.5 million annual increase for natural gas and ~~new rates~~no rate increase for electric which became effective ~~December 19, 2017.~~ 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 Tax Cuts and Jobs Act (TCJA), using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.

The settlement agreement provides for ~~a weighted cost~~the pass back of ~~capital~~plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of ~~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:


1)	excess deferred taxes for non-plant- related book/tax differences,


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 a~~its advanced metering infrastructure (AMI) investment and may defer the return on ~~equity~~the 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 Commission approved the settlement with one condition. The ~~settlement also resulted~~Commission required that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018 through April 30, 2018, discussed in item 2 above over a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%, annually.one year period beginning May 1, 2019.

Washington Commission Tax Deferral Filing

The ~~GRC also re-purposed~~Tax Cuts and Jobs Act (TCJA) was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the ~~benefit~~new corporate tax rate. PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for ~~PTCs and hydro-related treasury grants~~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 ~~fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. As the Company monetizes PTCs, which are PTCs used on the filed tax returns,~~ the regulatory liability ~~is transferred~~for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to ~~a reserve for Colstrip Units 1 and 2 decommissioning and remediation costs.~~

~~For further details regarding~~reflect the ~~2017 GRC filing, see Note 3, "Regulation and Rates"~~decrease in the federal corporate income tax rate from 35.0% to ~~the consolidated financial statements included in Item 8~~21.0%. The overall impact of the ~~Company’s Form 10-K~~rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas.

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 ~~ended December 31, 2017.~~January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

As a result of the Washington Commission’s final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2018 through February 28, 2019 will be addressed in PSE’s next GRC. The Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018 through April 30, 2018, discussed in item 2 above over a one year period beginning 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 assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with ~~some~~several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues ~~will~~ continue to be recovered on a per customer basis and electric fixed production energy costs ~~will~~are now be decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ~~expedited rate filing (ERF).~~ERF. Approved electric fixed production energy costs can ~~only~~also be changed in a ~~GRC or~~ power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On ~~June 30, 2018,~~February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

On March 31, 2019, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the ~~revenue~~reserve is ~~forecasted to be collected~~probable of collection within 24 months from the end of the annual period, the reserve can be ~~reversed.~~recognized as decoupling revenue. The analysis indicated that all of electric deferred revenue ~~for electric and natural gas~~ will be collected within 24 months of the annual period; therefore, ~~there were~~ no ~~adjustments~~adjustment was booked to ~~2017 or 2018~~2019 decoupling ~~revenue other than to record the previously unrecognized decoupling deferrals of $20.8 million at December 31, 2016.~~revenue.

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, PSE incurred ~~$8.9~~$38.4 million in storm-related electric transmission and distribution system restoration costs, of which ~~no current year amount was~~the Company deferred $1.1 million and $26.4 million as regulatory assets related to ~~a regulatory asset.~~storms that occurred in 2018 and 2019, respectively. This compares to ~~$20.8~~$5.7 million incurred in storm-related electric transmission and distribution system restoration costs for the ~~six~~three months ended ~~June 30, 2017,~~March 31, 2018, of which ~~$12.1 million~~no amount 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 approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

~~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 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. 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 filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. PSE’s proposal in the filing is to address both the excess deferred taxes and the deferred balance associated with the over-collection of income tax expense in PSE’s accounting petition. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas.

(8) Commitments 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 no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents.

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 increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to ~~$129.2~~$130.9 million and ~~$127.6~~$130.7 million as of ~~June 30, 2018~~March 31, 2019, and December 31, ~~2017,~~2018, respectively. However, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. 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 ~~will accelerate~~has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

OnIn 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 onin September ~~20,~~ 2016. OnIn 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~~paid a penalty of $1.5 million and is currently implementing a comprehensive inspection and remediation program. ~~However, litigation is still pending regarding damage and personal injury claims.~~

Other Commitments and Contingencies

There 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 our corporate offices and operations, real estate for our operating facilities and PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. Our finance leases are for office printers. Our 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 March 31,
(Dollars in Thousands)	2019
Finance lease cost:
Amortization of right-of-use asset	$	158
Interest on lease liabilities	9
Total finance lease cost	$	167

Operating lease cost¹	$	4,784

_______________


¹	^Includes^{$0.3 million}^{allocated to PLNG at PE related to the Tacoma land lease.}

Supplemental cash flow information related to leases was as follows:



Puget Energy and Puget Sound Energy	Three Months Ended March 31,
(Dollars in Thousands)	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	(4,346	)
Investing cash flow for operating leases¹	(438		)
Operating cash flow for finance leases	(9		)
Financing cash flows for finances leases	(158		)

_______________


¹	^Includes^{$0.3 million}^{allocated to PLNG at PE related to the Tacoma land lease.}

Supplemental balance sheet information related to leases was as follows:



Puget Sound Energy
(Dollars in Thousands)	At March 31,
Operating Leases	2019
Operating lease right-of-use asset	$	169,114

Operating leases liabilities current	$	(13,876	)
Operating lease liabilities long-term	(160,786		)
Total Operating lease liabilities:	$	(174,662	)

Finance Leases
Common Plant	$	1,395

Other current liabilities	$	(553	)
Other deferred credits	(864		)
Total finance lease liabilities	$	(1,417	)

Weighted Average Remaining Lease Term
Operating leases	13.66 years
Finance leases	3.02 years

Weighted Average Discount Rate
Operating leases	3.78		%
Finance leases	2.97		%

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



Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)	Future Minimum Lease Payments
At December 31,	Operating Leases			Finance Leases
2019 (remaining nine months)	$	15,505		$	430
2020	20,672			511
2021	20,598			376
2022	20,171			147
2023	19,213			11
Thereafter	132,889			—
Total lease payments	229,048			1,475
Less imputed interest	(54,386		)	(58		)
Total	$	174,662		$	1,417



Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)	Future Minimum Lease Payments
At December 31,	Operating Leases		Finance Leases
2019	$	20,635	$	495
2020	20,704		446
2021	20,630		311
2022	20,202		82
2023	19,223		—
Thereafter	132,889		—
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. 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-K~~10K for the year ended December 31, ~~2017.~~

~~(9) Other~~

~~Long-Term Debt~~

On June 4, 2018, PSE issued $600.0 million of 30-year Senior Notes under its senior note indenture at an interest rate of 4.223% with a maturity date of June 15, 2048. The proceeds from the issuance were used to pay the principal and accrued interest on the Company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and other general corporate expenses.

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, ~~2017.~~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), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma ~~LNG~~liquefied natural gas (LNG) facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners, Macquarie Capital Group Limited, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation (BCIMC), and the Alberta Investment Management ~~Corporation.~~Corporation (AIMCo). In August 2018, Macquarie Infrastructure Partners and Macquarie Capital Group Limited reached an agreement to sell their shares to Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V. and current owners, AIMCo and BCIMC. The sale 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.

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 (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;

Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate base and customer rates;

General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; and

Federal, state, and local taxes.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended ~~June 30, 2018~~March 31, 2019 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 ~~2018~~2019 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon ~~sufficient~~ 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 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 a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. 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~~Expedited Rate ~~Case~~ Filing

~~In January 2017,~~On November 7, 2018, PSE filed ~~its general~~an expedited rate ~~case (GRC)~~filing (ERF) with the Washington Commission. ~~The Washington Commission entered a final order accepting~~On January 22, 2019, all parties in the ~~multi-party~~proceeding reached an agreement on settlement terms. The settlement agreement ~~and determined~~was filed on January 30, 2019. On February 21, 2019, the ~~contested issues in~~Commission approved the ~~case on December 5, 2017 and new rates became effective December 19, 2017.~~ settlement with one condition. The Commission requires that PSE pass back the deferred balance associated with the tax over-collection from January 1, 2018, through April 30, 2018, over a one year period beginning May 1, 2019.

For further details regarding the ~~2017 GRC~~2018 ERF filing, see Note ~~3, "Regulation~~7, "Regulations and Rates" to the consolidated financial statements included in ~~Item 8~~part 1 of ~~the Company's Form 10-K for the period ended December 31, 2017.~~this report.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform. The ~~deferral~~deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%. The filing did not address excess deferred taxes or 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 through May 1, 2018, the requested effective date of the rate change). PSE’s proposal in the filing is to address both the excess deferred taxes and the deferred balance associated with the over collection of income tax expense in PSE’s accounting petition.

The Washington Commission approved the following PSE requests to change rates ~~annually under its electric and natural gas~~to reflect the new corporate tax ~~deferral filing:~~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)

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission. On December 5, 2017, the Washington Commission entered a final order accepting the multi-party settlement agreement and determining the contested issues in the case. The rates authorized by the Commission in the final order became effective December 19, 2017. For further details regarding the 2017 GRC filing, see Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2018.

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. ~~The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017.~~ Approved revenue per customer costs can only be changed in a GRC or ~~expedited rate filing (ERF).~~ERF. Approved electric fixed production energy costs can ~~only~~also be changed in a ~~GRC or~~ power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate cap which limits the amount of previously deferred revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism is to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

On March 31, 2019, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that all of electric deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2019 decoupling revenue.

The Washington Commission approved the following PSE requests to change rates for prior deferrals under its electric and natural gas decoupling mechanisms:


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)¹	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)¹
Electric:
May 1, 2019			0.9%	$20.6
May 1, 2018	(1.1)%	$(25.2)	(1.1)	(25.2)
May 1, 2017	2.0	41.9
May 1, 2016	1.0	20.8
Natural Gas:
May 1, 2019			(5.3)%	$(45.9)
May 1, 2018	1.7%	$15.9	1.7	15.9
May 1, 2017	2.4	22.4
May 1, 2016	2.8	25.4

_______________

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, $11.9 million for electric and $2.2 million for natural gas effective May 1, 2017, and $11.9 million for electric and $5.5 million for natural gas effective May 1, 2016.~~

As noted earlier, at the time of the filings below, the Company was 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)¹
Natural Gas:
2016 $47.4

~~_______________~~


¹	Existing deferrals after December 2017 may be included in customer rates beginning in May 2019, subject to subsequent application of the earnings test and the cap on decoupling related rate increases, which for natural gas customers, was changed from 3.0% to 5.0% as a result of the Washington Commission order in PSE's GRC.2018.

Electric Rates

Power Cost Adjustment Mechanism

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

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



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

OnIn September ~~30,~~ 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested was January 1, 2017, through December 31, 2017, when rates ~~went~~were to go 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 ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, in its PCA mechanism, PSE ~~over~~under recovered its power costs by ~~$15.3~~$43.1 million of which no$14.3 million amount was apportioned to customers. This compares to an ~~under~~over recovery of power costs of ~~$8.6~~$7.5 million for the ~~six~~three months ended ~~June 30, 2017~~March 31, 2018 of which no amounts were apportioned to customers. Power costs ~~decreased~~have been higher than the allowed base line in ~~2018 compared~~2019 which has led to ~~2017, although the effect of the lower power costs~~an increase in the PCA ~~mechanism~~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 which is one driver of increased power cost. This was ~~offset~~driven by colder temperatures in February and early March. Additionally, power prices increased during the period as compared to the prior year. Increase in prices are due to: 1) Cold weather in February and early March which drove regional loads up; 2) Westcoast pipeline capacity limitations contributed to higher natural gas and power prices; 3) An outage on a ~~decrease~~transmission line contributed to a liquidity crisis at Mid-C, resulting in ~~load used to calculate~~high market power prices; and 4) The relative prices of natural gas and power reduced the ~~baseline amount~~supply of natural gas-fired generation and ~~a slightly lower baseline rate in 2018.~~increased the demand for market power, increasing prices.

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 ~~the difference between~~ actual ~~conservation expenditures and the forecasted~~compared to

forecast conservation expenditures from the prior year, as well as ~~the difference between~~ actual ~~load and~~compared to the forecasted load set in rates.

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)	Average 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)	(0.8)	(18.0)
May 1, 2017	0.7	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 was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. ~~The~~After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the prior year.

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)	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)	(0.1)	(1.3)
May 1, 2017	(0.04)	(0.9)
May 1, 2016	0.3	5.7

Federal Incentive Tracker Tariff

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

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


Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2019			0.1%	$(38.7)
May 1, 2018	0.4%	$(40.1)	0.4	(40.1)
January 1, 2018	0.2	(48.2)	0.2	(48.2)
January 1, 2017	0.3	(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 receives from the Bonneville Power Administration (BPA). 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)

Natural Gas Rates

Natural Gas Conservation Rider

The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for ~~the difference between~~ actual ~~conservation expenditures and forecasted~~compared to forecast conservation expenditures from the prior year, as well as ~~the difference between~~ actual ~~load and~~compared to the forecasted load set in rates.

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

Effective Date
Average
Percentage
Increase (Decrease)
in Rates

Increase (Decrease)
in Revenue
(Dollars in Millions)

May 1, 2017 (0.1) (1.0)
May 1, 2016 0.3 2.9



Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)



May 1, 2019	0.1%	$1.1

Natural Gas Property Tax Tracker Mechanism


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)	Average 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)	(0.2)	(2.2)
May 1, 2017	(0.1)	(1.1)
May 1, 2016	0.4	3.5

Natural Gas Cost Recovery Mechanism

The purpose of the ~~cost recovery mechanism (CRM)~~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 ~~or pending with~~ the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates:

Effective Date Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2018 (proposed as originally filed and pending approval) 0.4% $3.7
November 1, 2017 0.5 4.9
November 1, 2016 0.6 5.6



Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2018	0.5%	$5.0

Purchased Gas Adjustment

PSE has a ~~purchased gas adjustment (PGA)~~PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 1.1st 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 one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. Due to the large commodity balance, the amortization period will take place over two years (May 2019-April 2021) in order to limit impacts on customer’s bills.

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)



Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	6.3%	$54.0
November 1, 2018	(10.9)	(98.4)

Other Proceedings

Large Customer Retail Wheeling

~~On October 7, 2016,~~Following multiples discussions between PSE, ~~filed~~the Microsoft Corporation, and others, and after completing a ~~tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to~~negotiated regulatory process, in July 2017, the ~~case reached~~Washington Commission issued an ~~all-party settlement that converted the tariff to~~order approving a special contract ~~only allowing~~between PSE and Microsoft relating to retail access for ~~the~~Microsoft loads ~~of the Microsoft Corporation~~ 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 will pay a transition fee that will be a straight pass-through to customers and (v) Microsoft will 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~~began taking service under the special contract ~~until it has~~on April 1, 2019 after meeting the ~~required metering installed, has contracts for~~eligibility requirements under the ~~supply and transmission of its power supply and pays the transition fee.~~special contract.

Voluntary Long-Term Renewable Energy

OnEffective September ~~28,~~ 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy ~~product, effective September 30, 2016.~~product. This provides customers with electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000 MWh) and government customers. The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW that will be constructed in the region by a developer under contract to PSE to meet the demand for this voluntary renewable energy product. ~~PSE anticipates that customers will start receiving energy through this program~~The project is expected to begin generating power in late 2019. Twenty-one customers have fully subscribed to the anticipated output of the project.

In July 2018, the Washington Commission approved a second phase of the Green Direct product. The phase 2 offering will be a blend of the phase 1 wind and a solar project. In October 2018, the Washington Commission approved an expansion of the solar project from 120 MW to 150 MW. Phase 1 customers will receive wind through 2020; and then will receive the blended energy in 2021. Open enrollment for phase 2, which is fully subscribed, began on August 31, 2018. Twenty customers will start receiving energy through the program in 2021.

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

Other Factors and Trends

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to 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. In October 2017, Puget Energy and PSE each entered into new 5-year credit facilities that replaced the previous 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. PSE also faces increasing competition for sales to its retail customers through alternative methods of electric energy generation, including solar and other self-generation methods. In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE.

Results of Operations

Puget Sound Energy

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 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 chart displays the details of PSE's electric margin changes for the three months ended ~~June 30, 2017~~March 31, 2018 and ~~2018:~~

~~______________~~

^*~~Includes decoupling cash collections, ROR excess earnings, and decoupling 24-month revenue reserve.~~2019:

~~Three months ended June 30, 2017 compared to 2018~~

~~Electric Operating Revenue~~

~~Electric operating revenues~~ decreased $28.3 million primarily due to a decrease in decoupling revenue of $28.2 million and lower electric retail sales of $12.9 million; partially offset by other decoupling revenue of $5.7 million and transportation and other revenues of $5.6 million. These items are discussed in detail below.

~~Electric retail sales~~ decreased $12.9 million primarily due to a decrease in rates of $8.2 million from the following: (i) a decrease in rates of 3.5% as a result of a decrease in corporate tax rates in the TCJA filing, (ii) a decoupling rate mechanism decrease of 1.1% annually effective May 2018, and (iii) a $4.7 million decrease primarily from lower retail residential electricity usage of 2.5% compared to the prior year. The reduced usage was primarily due to a decrease in heating degree days of 15.1% compared to 2017.

~~Decoupling revenue~~ decreased $28.2 million primarily due to $23.4 million of PCA fixed cost deferrals. In 2017, the PCA fixed cost deferrals were not load shaped within the mechanism, which led to a large over-collection. In 2018, PCA fixed costs are load shaped within the decoupling mechanism to more accurately reflect annual load trends. In addition, the decoupling deferrals decreased $4.8 million due to a decrease in allowed revenue per customer slightly offset by a decrease in electricity usage as noted above. As a result, actual revenue was closer to PSE's allowed revenue per the decoupling mechanism compared to 2017.

~~Other decoupling revenue~~ increased $5.7 million due to a decrease in cash collections of $3.5 million due to lower amortization rates and reduced usage and in 2018 a true-up of $2.3 million was recorded for 2017 electric ROR to $9.5 million.

~~Transportation and other revenue~~ increased $5.6 million primarily due to a change in production tax credit (PTC) deferral revenue of $7.6 million for the re-purpose of the PTCs and an increase in net wholesale natural gas sales of $3.1 million due to an increase of 4.3% in wholesale electricity prices; partially offset by tax reform deferrals for revenue subject to refunds of $5.1 million.

~~Electric Power Costs~~

~~Electric power costs~~ ~~decreased $6.1 million primarily due to a decrease of $4.4 million of electric generation fuel expense. This item is discussed in detail below:~~

~~Electric generation fuel~~ expense decreased $4.4 million primarily due to a $3.4 million reduction of coal generation costs primarily at Colstrip units 1 and 2 for variable fuel costs due to a 18.1% decrease in production as units 1 and 2 were shut down for maintenance during the second quarter of 2018. In addition, there was a $1.0 million reduction in combustion turbine generation costs primarily due to an increase in wind generation of 4.2% and reduction in customer usage.

~~The following chart displays the details of PSE's electric margin changes for the six months ended June 30, 2017 and 2018:~~

______________

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

~~Six~~Three months ended ~~June 30, 2017~~March 31, 2018 compared to ~~2018~~2019

Electric Operating Revenue

Electric operating revenues increased ~~$2.4~~$99.3 million from the prior year primarily due to ~~transportation and~~an increase in other revenues of ~~$28.9~~$92.4 million, ~~and~~an increase in sales to other utilities of ~~$3.7~~$15.8 million and an increase in other decoupling revenue of $9.9 million; partially offset by ~~lower~~a decrease in electric retail sales of ~~$20.9~~$12.5 million and a decrease in decoupling revenue of ~~$10.8~~$6.3 million. These items are discussed in detail below.

Electric retail sales decreased ~~$20.9~~$12.5 million due to a decrease in rates of ~~$36.1~~$34.9 million, offset by an increase of $22.3 million from ~~lower~~additional retail electricity usage of ~~3.0%~~3.3% compared to the prior year and partially offset by an increase in rates of $15.2 million due to the decoupling rate mechanism rate increase of 2.0% annually effective May 2017 and the GRC rate increase of 0.9% annually effective December 2017.year. The ~~rate increases were partially offset by rate decrease in May 2018 of 3.5% due to change in corporate tax rates as a result of TCJA. The reduced~~additional usage was due to ~~a decrease~~an increase of residential and commercial use per customer of ~~4.8%~~5.2% and ~~1.1%~~0.9%, respectively, ~~primarily due to a decrease~~which was driven by an increase in heating degree days of ~~12.0%~~3.4% and an increase in retail customers of 1.4% compared to ~~2017.~~2018. The rate decrease was attributable to the annual decoupling rate mechanism rate decrease of 1.1% and a 3.4% decrease due to lower corporate tax rates resulting from the TCJA, which both became effective in May 2018.

Sales to other utilitiesincreased ~~$3.7~~$15.8 million due to a ~~9.8%~~12.8% increase in volumes ~~sold~~from an additional 111.8% of combustion turbine generation as a result of favorable heat rates and increased demand for market power, in addition to a ~~13.9%~~115.7% increase in ~~price. EIM sales drove the increase in volumes.~~electric wholesale prices due to sustained cold weather leading to increased demand and regional gas supply constraints.

Decoupling revenue decreased ~~$10.8~~$6.3 million, the combination of a $2.4 million decrease in delivery deferral revenues and a $3.9 million decrease in PCA fixed cost deferral revenues, driven by lower allowed rate per customer and increased usage, as noted above in the retail revenue section. This resulted in allowed delivery and FPC revenues being closer to actual delivery and FPC revenues in the current year than in prior year.

Other decoupling revenue increased $9.9 million , primarily due to an $8.1 million increase year-over-year related to a decrease in current year amortization of previous years' decoupling deferrals resulting from lower amortization rates. In addition, in 2018, estimated earnings in excess of ~~$9.2 million as driven~~allowed ROR were trued up to match actual earnings in excess of allowed ROR by actual revenue being closer to PSE's allowed revenue per the decoupling mechanism compared to 2017. This was primarily driven by a decrease in allowed revenue per customer compared to 2017 which was offset by lower customer usage. The remaining $1.6 million decrease is a result of fixed production costs collection being greater than allowed compared to 2017.$1.5 million.

Transportation and other revenue increased ~~$28.9~~$92.4 million primarily due to an increase in net wholesale non-core natural gas sales of $88.6 million and tax reform deferrals in 2018 for revenue subject to refunds of $18.9 million, offset by a ~~change~~decrease in ~~PTC~~production tax credit (PTC) deferral revenue of ~~$51.2~~$16.5 million for the re-purpose of the ~~PTCs; partially~~PTCs. The increase in net wholesale non-core natural gas sales was due to an approximately 385% increase in the average price of the non-core gas sold in 2019 compared to 2018, offset by ~~tax reform deferrals for revenue subject~~an 11% decrease in sales volume and a $29.8 million increase in the total cost of the non-core gas sold due to ~~refunds~~an approximately 141% increase in the average price of ~~$24.1 million.~~non-core gas purchases. The 2019 increase in gas prices was due to the continued effect of the Enbridge pipeline rupture which led to a decrease in pipeline capacity in the region at the same time that there was compressor issues at a gas storage facility limiting gas deliverability, and higher than expected load due to the cold weather in 2019. Also contributing to the net increase was a $7.7 million decrease in gas hedging costs, with 2019 seeing a $0.8 million gain.

Electric Power Costs

Electric power costs ~~decreased $40.9~~increased $150.1 million primarily due to ~~a decrease~~an increase of ~~$26.1~~$116.5 million of purchased electricity costs and ~~a decrease~~an increase of ~~$13.3~~$34.8 million of electric generation fuel expense. These items are discussed in detail ~~below:~~below.

Purchased electricity expense ~~decreased $26.1~~increased $116.5 million primarily due to a ~~7.3%~~77.5% increase in wholesale prices and partially offset by a 1.1% decrease in wholesale electricity ~~purchases and a 1.4% decrease in wholesale prices. The decrease in purchases was primarily~~purchases. Spot power prices at Mid-Columbia hit an 18-year high largely driven by ~~a decrease in load~~record-breaking natural gas prices and ~~an increase of wind and combustion turbine generation of 27.8% and 10.5%, respectively, which decreased the need to purchase additional wholesale power.~~sustained cold weather.

Electric generation fuel expense ~~decreased $13.3~~increased $34.8 million primarily due to a ~~$10.1~~$32.9 million ~~reduction~~increase in combustion turbine generation costs primarily driven by an increase in generation of 111.8% as a result of ~~a reduction in peaker combustion turbine generation due to~~ favorable ~~wholesale electricity prices~~heat rates and reduced wind and hydro production. ~~There was also a $3.2 million reduction of coal generation costs primarily~~Additionally, all-time high natural gas prices at ~~Colstrip units 1 and 2~~Sumas, which were largely due to ~~a shutdown during the second quarter of 2018 for maintenance.~~regional natural gas supply constraints and cold weather leading to increased demand and increased fuel costs.

Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through ~~to customers~~ 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~~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 chart displays the details of PSE's natural gas margin changes for the three months ended ~~June 30, 2017~~March 31, 2018 and ~~2018:~~2019:

_______________

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

Three months ended ~~June 30, 2017~~March 31, 2018 compared to ~~2018~~2019

Natural Gas Operating Revenue

Natural gas operating revenue decreased ~~$19.9~~$25.6 million primarily due to a decrease of ~~$19.1~~$20.9 million in total retail sales, ~~due to~~ a decrease of ~~natural gas usage, a decrease~~$11.2 million in ~~transportation~~other decoupling revenue and ~~other revenue of $2.9 million and a decrease of $2.3~~$2.6 million in decoupling revenue; partially offset by ~~a $4.4 million~~an increase in transportation and other ~~decoupling revenue.~~revenue of $9.1 million. These items are discussed in detail below.

Natural gas retail sales revenue decreased ~~$19.1~~$20.9 million due to a decrease in rates of ~~$11.5~~$44.8 million, offset by an increase in natural gas sales of $23.9 million, which is a result of ~~a decrease~~an increase in natural gas load of ~~7.6% from 2017~~5.1%. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 8.7% and 5.1%, respectively, compared to 2018, as a result of a 3.4% increase in heating degree days, which increased the natural gas heating load compared to prior year. The decrease in rates was primarily driven by a decrease in ~~revenue per therm~~PGA rates of ~~$7.6 million. The~~10.9%, a 2.7% decrease ~~in revenue per therm was primarily~~ due to rate changes from the following filings: GRC which decreased rates 3.8% annually effective December 2017, PGA which decreased rates 3.3% annually effective November 2017, 3.0% decrease in May 2018 for the change inlower corporate tax ~~rate due to~~rates resulting from the TCJA, and iswas offset by ana 1.7% increase in decoupling ~~rates of 1.7% annually effective May 2018, see~~rates. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. Natural gas load decreased primarily due to the decrease in average therms used as a result of a 15.1% decrease in heating degree days, which decreased the natural gas heating load compared to prior year.

Decoupling revenue decreased ~~$2.3 million~~$2.6 million. This is primarily ~~due actual~~attributable to a lower allowed rate per customer and

increased usage, as noted above in the retail revenue section. This resulted in allowed natural gas revenues being closer to PSE's allowed revenue per the decoupling mechanism compared to 2017. This was primarily driven by a decrease in allowed revenue per customer compared to 2017 which was offset by lower customer usage as discussedactual natural gas revenues in the ~~retails sales above.~~

current year than in prior year.

Other decoupling revenue ~~increased $4.4~~decreased $11.2 million, primarily ~~driven~~due to an $8.8 million decrease year-over-year related to an increase in current year amortization of previous years' decoupling deferrals resulting from higher amortization rates and increased natural gas usage in the current year. In addition, in 2018, estimated earnings in excess of allowed ROR were trued up to match actual earnings in excess of allowed ROR by ~~ROR sharing accrual of $5.2 million in 2017 as compared to no ROR sharing accrual in 2018.~~$3.4 million.

Transportation and other revenue decreased ~~$2.9~~$9.1 million primarily due to tax reform deferrals for revenue subject to refund in 2018 of ~~$2.0~~$8.5 million.

Natural Gas Energy Costs

Purchased natural gas expense decreased ~~$9.3~~$28.2 million due to a decrease in natural gas costs included in PGA rates ~~effective November 1, 2017 as compared to those effective November 1, 2016, and a decrease~~partially offset by an increase in natural gas usage of ~~7.6%~~5.1%.

~~The following chart displays the details of PSE's natural gas margin changes for the six months ended June 30, 2017 and 2018:~~

~~_______________~~

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

~~Six months ended June 30, 2017 compared to 2018~~

~~Natural Gas Operating Revenue~~

~~Natural gas operating revenue~~ decreased $89.7 million primarily due to a decrease of $68.8 million in total retail sales due to a decrease of natural gas usage and natural gas rates, a decrease of $11.6 million in other decoupling revenue and a decrease in transportation and other revenue of $11.5 million, partially offset by a $2.2 million increase in decoupling revenue. These items are discussed in detail below.

~~Natural gas retail sales revenue~~ decreased $68.8 million due to a decrease of $48.1 million in natural gas sales, which is a result of a decrease in natural gas load of 8.6% from 2017 and a decrease in revenue per therm of $20.7 million. The decrease in revenue per therm was primarily due to a rate changes from the following filings: GRC which decreased rates 3.8% annually effective December 2017, PGA which decreased rates 3.3% annually effective November 2017, 3.0% decrease in May 2018 for the change in corporate tax rate due to the TCJA and is offset by an increase in decoupling

rates of 2.4% and 1.7% annually effective May 2017 and May 2018, respectively, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes. Natural gas load decreased primarily due to the decrease in average therms used per residential and commercial customers of 9.4% and 6.9%, respectively, compared to 2017, as a result of a 12.0% decrease in heating degree days, which decreased the natural gas heating load compared to prior year.

~~Decoupling revenue~~ increased $2.2 million primarily due to a decrease in use per customer, driven by a decrease in heating degree days as discussed above in natural gas retail sales. This caused actual revenue to decrease below PSE's allowed revenue, which increased decoupled revenue in 2018. The decrease in usage was partially offset by a decrease in allowed revenue per customer in 2018.

~~Other decoupling revenue~~ decreased $11.6 million year-over-year due to the following: (i) in 2016, there was $19.6 million of decoupling deferred revenue that could not be collected within 24 months. This was recognized in the first quarter of 2017 as it met the alternative revenue program revenue recognition guidelines. There was no deferred revenue at 2017 year end and therefore, no additional revenue recognized in the first two quarters of 2018, (ii) offset by a $5.8 million ROR accrual in 2017 as compared to no accrual in 2018 due to under earning by the Company.

~~Transportation and other revenue~~ ~~decreased $11.5 million primarily due to tax reform deferrals for revenue subject to refund of $10.5 million.~~

~~Natural Gas Energy Costs~~

~~Purchased natural gas~~ expense decreased $34.5 million due to a decrease in natural gas costs included in PGA rates effective November 1, 2017 as compared to those effective November 1, 2016, and a decrease in natural gas usage of 8.6%.

Other Operating Expenses and Other Income (Deductions)

The following chart displays the details of PSE's operating expenses and other income (deductions) for the three months ended ~~June 30, 2017~~March 31, 2018 and ~~2018:~~2019:

Three months ended ~~June 30, 2017~~March 31, 2018 compared to ~~2018~~2019

Other Operating Expenses

Net unrealized (gain) loss on derivative instruments ~~expense decreased $10.7~~increased $14.2 million ~~from~~to a ~~loss~~net gain of ~~$3.8~~15.2 million. The primary ~~driver~~drivers for the ~~decrease~~increase in ~~losses consists of a $9.5 million gain~~gains was due to an increase in the weighted average electricity and natural gas forward prices of ~~8.3%.~~33.7%, resulting in a $40.2 million increase, and 32.3%, resulting in a $33.7 million increase, respectively. However, these increases were offset by settlements of $38.7 million and $21.0 million of electric and natural gas trades, respectively, previously recorded as gains.

Utility operations and maintenance expense decreased ~~$5.4~~$2.6 million primarily ~~driven by~~due to a decrease in ~~the following: (i) decrease of $2.7 million in wind generation contract maintenance due to replacement of capital units of property~~low income assistance

funding expense.

Non-utility expense and ~~(ii) decrease of $1.3~~other increased $3.3 million due to ~~lower meter service contracts tied to the Consumer Price Index~~an increase in ~~2018 compared to 2017.~~long-term incentive plan expense of $1.8 million and an increase in biogas purchase expense of $1.4 million.

Depreciation and amortization expense ~~increased $31.0~~decreased $7.4 million primarily ~~due to~~driven by: (i) a ~~depreciation rate change effective December 2017 as a result of the GRC and the following: (i)~~decrease in amortization of PTC regulatory liability of ~~$7.6~~$16.5 million in the first quarter of 2019 compared to the same period in 2018; and partially offset by (ii) electric depreciation expense increased ~~$15.7~~$2.2 million, primarily due to net asset additions to ~~production and~~ distribution of ~~$10.8 million and $173.7 million, respectively;~~$237.5 million; (iii) an increase of ~~$4.0~~$10.1 million due to net additions of ~~$102.3~~$236.3 million of computer software; and (iv) an increase of storm damage and regulatory amortization of $3.7 million and (v) an increase in natural gas environmental cost amortization of $2.2 million. These increases were partially offset by (i) conservation amortization decreased $1.7 million primarily due to a decrease of electric rate change of 0.8% annually effective May 1, 2018 and lower customer usage due to lower heating degree days in 2018 as compared to 2017 and (ii) a decrease in natural gas depreciation expense of ~~$3.8~~$1.8 million primarily due to net asset additions to distribution of $221.8 million offset by a depreciation rate change to a lower rate.

Taxes other than income taxes decreased ~~$3.7~~$2.4 million primarily due to decreases in municipal taxes of ~~$1.3~~$2.0 million and state excise taxes of $1.4 million as a result of a decrease in retail revenue.

Other Income, Interest Expense and Income Tax Expense

~~Interest~~ Other Income/expense ~~decreased $3.7~~increased $3.2 million primarily ~~related to lower interest rates on long-term debt~~ due to a $1.3 million increase in the ~~refinancing~~Washington Commission Allowance for Funds used During Construction (AFUDC) driven by a change in the rate and an increase in eligible CWIP, as well as a $1.3 million increase in pension non-service costs recorded in 2019 as compared to 2018. For further details regarding the non-service cost component, see Note 6, "Retirement Benefits" to the consolidated financial statements included in Item 1 of ~~the $250.0 million in junior subordinated notes and $200.0 million in senior secured notes at a lower interest.~~this document.

Income tax expense decreased ~~$15.8~~$2.9 million primarily driven by ~~the following: (i) approximately $4.7 million from the impact of tax reform with a decrease in statutory tax rate from 35% to 21% and~~ a decrease in pre-tax ~~income with a tax effect of approximately $8.4 million.~~

~~The following chart displays the details of PSE's operating expenses and other income (deductions) for the six months ended June 30, 2017 and 2018:~~

~~Six months ended June 30, 2017 compared to 2018~~

~~Other Operating Expenses~~

~~Net unrealized (gain) loss on derivative instruments expense~~ decreased $31.0 million from a loss of $23.1 million. The primary drivers for the decrease in losses consists of a $31.8 million gain due to an increase in electricity and natural gas forward prices of 13.9% and 8.3%, respectively. The increase in the weighted average wholesale electric and natural gas forward prices resulted in a $6.3 million gain and a $25.5 million gain, respectively.

~~Utility operations and maintenance~~ expense increased $3.0 million primarily driven by increased labor expenses of $4.7 million due to an increase in system reliability projects, $4.4 million due to an increase in locate services; partially offset by a $3.2 million net decrease storm expense from less storms in 2018 compared to 2017 and a $1.4 million decrease in tree trimming services.

~~Depreciation and amortization~~ expense increased $102.3 million primarily due to a depreciation rate change effective December 2017 as a result of the GRC which increased and the following: (i) amortization of PTC regulatory liability of $51.2 million in 2018; (ii) electric depreciation expense increased $31.3 million, primarily due to net asset additions to production and distribution of $10.8 million and $173.7 million, respectively; (iii) an increase of $8.1 million due to net additions of $102.3 million of computer software: (iv) an increase of storm damage and regulatory amortization of $7.4 million; (v) an increase in natural gas environmental cost amortization of $4.4 million; these increases were partially offset by (vi) a decrease in natural gas depreciation expense of $7.6 million primarily due to a depreciation rate change to a lower rate.

~~Taxes other than income taxes~~ decreased $11.2 million primarily due to decreases in municipal taxes of $4.3 million and state excise taxes of $3.6 million, as a result of a decrease in retail revenue; additionally, a decrease of $3.4 million related to the property tax tracker, which decreased due to load.

~~Other Income, Interest Expense and Income Tax Expense~~

~~Interest expense~~ decreased $5.3 million primarily related to lower interest rates on long-term debt due to the refinancing of the $250.0 million in junior subordinated notes and $200.0 million in senior secured notes at a lower interest.

~~Income tax expense~~ decreased $65.9 million primarily driven by the following: (i) approximately $30.6 million from the impact of tax reform with a decrease in statutory tax rate from 35% to 21%, (ii) a decrease in pre-tax book income with a tax effect of approximately $14.7 million, and (iii) approximately $23.8 million due to the impact of tax reform on utility plant related deferred taxes. The impact of tax reform has had a significant effect on the effective tax rate for PSE and Puget Energy. Management estimates the effective tax rate for 2018 to be between 10% and 15% for PSE and between 6% and 12% for Puget Energy.income.

Puget Energy

Primarily, all operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three months ended ~~June 30, 2017~~March 31, 2018 and ~~2018~~2019 are as follows:

Three months ended ~~June 30, 2017~~March 31, 2018 compared to ~~2018~~2019

Summary Results of Operation

Puget Energy’s net income decreased for the three months ended ~~June 30, 2018~~March 31, 2019 by ~~$31.6~~$14.7 million primarily due to a decrease over the prior year for PSE's net ~~income as well as decreases in income tax benefit:~~

~~Income tax benefit~~ ~~decreased by $6.0 million due primarily to the impact of tax reform with a decrease in statutory tax rate from 35% to 21% as well as a decrease in pre-tax~~ income.

~~Puget Energy's net income (loss) for the six months ended June 30, 2017 and 2018 are as follows:~~

~~Six months ended June 30, 2017 compared to 2018~~

~~Summary Results of Operation~~

~~Puget Energy’s net income decreased for the six months ended June 30, 2018 by $12.3 million primarily due to a decrease in non-utility and other expense, as well as a decrease in income tax benefit:~~

~~Other income~~ increased by $5.1 million primarily as a result of the reclassification of the non-service cost component of pension benefit cost. For further information on this reclassification, see Note 6, "Retirement Benefits" in the Combined Notes to Consolidated Financial Statements in Item I.

•~~Non utility expense and other~~ ~~decreased by~~ ~~$6.4 million~~ ~~primarily due to a reduction in qualified pension expense.~~

~~Income tax benefit~~ ~~decreased by $5.6 million due primarily to the impact of tax reform with a decrease in statutory tax rate from 35% to 21% as well as a decrease in pre-tax income.~~

Capital Requirements

Contractual Obligations and Commercial Commitments

During the ~~six~~three months ended ~~June 30, 2018,~~March 31, 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 ~~year~~period ended December 31, ~~2017.~~2018.

The following are the Company's aggregate availability under commercial commitments as of ~~June 30, 2018:~~March 31, 2019:


Puget Sound Energy and Puget Energy	Amount of Available Commitments Expiration Per Period												Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2018		2019 - 2020		2021 - 2022		Thereafter			Total			2019		2020-2021		2022-2023		Thereafter
Commercial commitments:
PSE revolving credit facility¹	800,000			—		—		800,000		—
Inter-company short-term debt¹	$	30,000		$	—	$	—	$	—	$	30,000
PSE revolving credit facility													$	800,000		$	—	$	—	$	800,000	$	—
Inter-company short-term debt													30,000			$	—	—		—		30,000
Total PSE commercial commitments	830,000			—		—		800,000		30,000			$	830,000		$	—	$	—	$	800,000	$	30,000
Puget Energy revolving credit facility²	660,449			—		—		660,449		—
Less: Inter-company short-term debt elimination¹	$	(30,000	)	$	—	$	—	$	—	$	(30,000	)
Puget Energy revolving credit facility													774,700			—		—		774,700		—
Less: Inter-company short-term debt elimination													(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	1,460,449			—		—		1,460,449		—			$	1,574,700		$	—	$	—	$	1,574,700	$	—

~~_______________~~


¹ For further discussion, see Management's Discussion and Analysis, "Financing Program" in Item 2.	~~For more information, see "Financing Program - Puget Sound Energy - in the Management's Discussion and Analysis Section".~~


²	~~For more information, see "Financing Program - Puget Energy - in the Management's Discussion and Analysis Section".~~

Off-Balance Sheet Arrangements

As of ~~June 30, 2018,~~March 31, 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.

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), totaled ~~$452.2~~$218.0 million for the ~~six~~three months ended ~~June 30, 2018.~~March 31, 2019. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:


Capital Expenditure Projections
(Dollars in Thousands)	2018		2019		2020		2019		2020		2021
Total energy delivery, technology and facilities expenditures	$	1,003,000	$	839,000	$	740,000	$	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 Energy	Six Months Ended June 30,									Three Months Ended March 31,
(Dollars in Millions)	2018			2017			Change			2019			2018			Change
Net income	$	189,818		$	193,746		$	(3,928	)	$	147,302		$	163,037		$	(15,735	)
Non-cash items¹	351,940			408,783			(56,843		)	188,451			194,057			(5,606		)
Changes in cash flow resulting from working capital²	153,022			175,755			(22,733		)	(76,349		)	57,233			(133,582		)
Regulatory assets and liabilities	4,591			(46,101		)	50,692			(15,838		)	20,871			(36,709		)
Other noncurrent assets and liabilities³	(14,956		)	(32,507		)	17,551			(11,959		)	(14,344		)	2,385
Net cash provided by operating activities	$	684,415		$	699,676		$	(15,261	)	$	231,607		$	420,854		$	(189,247	)

_______________


¹	Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and other miscellaneous non-cash items.


²	Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayment, PGA, accounts payable and accrued expenses.


³	Other non-current assets and liabilities include funding of pension liability.

~~Six~~Three Months Ended ~~June 30, 2018~~March 31, 2019 compared to ~~2017~~2018

Cash generated from operations for the ~~six~~three months ended ~~June 30, 2018~~March 31, 2019 decreased by ~~$15.3~~$189.2 million including a net income decrease of ~~$3.9~~$15.7 million. The following are significant factors that impacted PSE's cash flows from operations:

Cash flow adjustments resulting from non-cash items decreased ~~$56.8~~$5.6 million primarily due to decreases in unrealized gains and losses on derivative instruments of $14.2 million, depreciation and amortization of $3.8 million, and conservation amortization of $3.6 million offset by production tax credit monetization of $16.5 million.

Cash flows resulting from changes in working capital decreased $133.6 million primarily due to changes in ~~deferred income tax and tax credits~~power gas adjustments of ~~$76.1 million, production tax credit monetization of $51.2 million and derivative instruments of $31.0 million offset by changes in depreciation and amortization of $101.9~~$144.8 million. ~~For further discussion, see note 7, "Regulation and Rates" and Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.~~

Cash ~~flow~~flows resulting from regulatory assets and liabilities ~~increased $50.7~~decreased $36.7 million primarily due to ~~deferred accounting treatment for~~increases in revenue subject to refund and the ~~impacts of tax reform and decoupling collections. For further discussion, see Management's Discussion and Analysis, "Electric Operating Revenue" and "Natural Gas Operating Revenue"~~power cost adjustment mechanism in ~~Item 2.~~2018 compared to 2019.


Puget Energy	Six Months Ended June 30,									Three Months Ended March 31,
(Dollars in Millions)	2018			2017			Change			2019			2018			Change
Net income	$	(39,276	)	$	(30,921	)	$	(8,355	)	$	(15,148	)	$	(16,140	)	$	992
Non-cash items¹	(2,725		)	(13,458		)	10,733			(5,260		)	(2,377		)	(2,883		)
Changes in cash flow resulting from working capital²	3,438			(8,415		)	11,853			(11,498		)	300			(11,798		)
Regulatory assets and liabilities	—			—			—			—			—			—
Other noncurrent assets and liabilities³	(6,655		)	18,788			(25,443		)	(1,504		)	(3,316		)	1,812
Net cash provided by operating activities	$	(45,218	)	$	(34,006	)	$	(11,212	)	$	(33,410	)	$	(21,533	)	$	(11,877	)

_______________


¹	Non-cash items include depreciation, amortization, deferred income taxes, net unrealized (gain) loss on derivative instruments, AFUDC-equity, PTCs and other miscellaneous non-cash items.


²	Changes in working capital include receivables, unbilled revenue, materials/supplies, fuel/gas inventory, income taxes, prepayments, PGA, accounts payable and accrued expenses.


³	Other noncurrent assets and liabilities include funding of pension liability.

~~Six~~Three Months Ended ~~June 30, 2018~~March 31, 2019 compared to ~~2017~~2018

Cash generated from operations for the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, in addition to the changes discussed at PSE above, decreased by ~~$11.2~~$11.9 million compared to the same period in ~~2017.~~2018. The change was primarily impacted by the factors explained below:

Cash flow resulting from ~~non-cash items increased $10.7 million primarily due to changes in deferred income taxes.~~

~~Cash flow resulting from~~ working capital ~~increased $11.9~~decreased $11.8 million primarily due to changes in accounts receivable.

Cash flow resulting from other noncurrent assets and liabilities decreased $25.4 million primarily due to the reclassification of construction work-in-process related to other property and investments.

Financing Program

The ~~Company's~~Company’s external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget ~~Energy's~~Energy’s and ~~PSE's~~PSE’s credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy and PSE. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets ~~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 ~~Facilities~~Facility

As of ~~June 30, 2018,~~March 31, 2019, PSE had an $800.0 million credit facility to meet short-term liquidity needs. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. The unsecured revolving credit facility matures in October 2022.

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of ~~June 30, 2018,~~March 31, 2019, PSE was in compliance with all applicable covenant ratios.

The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of ~~June 30, 2018,~~March 31, 2019, no amounts were drawn and outstanding under PSE's credit ~~facility. No letters of credit were outstanding~~facility and ~~$28.0~~$432.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a ~~$3.1~~$3.0 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note

In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of ~~June 30, 2018,~~March 31, 2019, PSE had no outstanding balance under the Note.

~~Long Term Debt~~

On March 5, 2018, PSE commenced a tender offer and related consent solicitation to purchase any and all of the outstanding $250.0 million 6.974% Series A Enhanced Junior Subordinated Notes due June 1, 2067. Holders of the notes received $1,005 per $1,000 principal amount of notes plus accrued and unpaid interest for notes tendered and accepted by the early tender payment deadline of March 16, 2018. Holders of notes tendered after the early tender payment deadline, but prior to the tender offer expiration on April 2, 2018 were to receive the tender offer consideration of $975 per $1,000 of principal amount of the notes plus accrued but unpaid interest. A total of $193.4 million in principal amount of notes were tendered by the early payment deadline and no notes were tendered after the early payment deadline. On March 20, 2018, $194.9 million was paid to the holders of the tendered notes. This amount included the principal, early tender consideration and accrued interest up to, but not including March 20, 2018.

Concurrently with the tender offer, PSE solicited consents from a majority (in principal amount) of the holders of PSE’s 6.274% Senior Notes due March 15, 2037 to terminate the replacement capital covenant granted to the holders of those notes. The termination of the covenant was necessary because it included restrictions related to repurchases, redemptions and repayments of the 6.974% Series A Enhanced Junior Subordinated Notes. PSE received consents from holders of 87.7% of the 6.274% Senior Notes and paid a consent fee totaling $2.6 million to those holders on March 19, 2018.

On March 28, 2018, PSE issued a notice of redemption, effective April 27, 2018, for the remaining $56.6 million principal amount of the 6.974% Series A Enhanced Junior Subordinated Notes. The notes were redeemed at a price equal to 100% of their principal amount plus accrued and unpaid interest up to, but excluding the redemption date.

On June 4, 2018, PSE issued $600.0 million of 30 year Senior Notes under its senior note indenture at an interest rate of 4.223% with a maturity date of June 15, 2048. The proceeds from the issuance were used to pay the principal and accrued interest on the company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and other general corporate expenses.

Debt Restrictive Covenants

The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.

PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests at ~~June 30, 2018,~~March 31, 2019, PSE could issue:

Approximately ~~$2.0~~$2.3 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$3.3~~$3.8 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at ~~June 30, 2018;~~March 31, 2019; and

Approximately ~~$511.0~~$614.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately ~~$851.7 million~~$1.0 billion of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at ~~June 30, 2018.~~March 31, 2019.

At ~~June 30, 2018,~~March 31, 2019, PSE had approximately ~~$7.1~~$7.5 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, PSE filed a shelf registration statement under which it may issue, as of the date of this report, up to $200.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The shelf registration will expire in November 2019.

Dividend Payment Restrictions

The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At ~~June 30, 2018,~~March 31, 2019, approximately ~~$753.6~~$877.7 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was ~~49.6%~~44.5% at ~~June 30, 2018~~March 31, 2019 and the EBITDA to interest expense was ~~5.6~~5.4 to 1.0 for the twelve months ended ~~June 30, 2018.~~March 31, 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.

Puget Energy

Credit Facility

At ~~June 30, 2018,~~March 31, 2019, Puget Energy maintained an $800.0 million credit facility which matures in October 2022. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of ~~June 30, 2018,~~March 31, 2019, there was ~~$139.6~~$25.3 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 ~~June 30, 2018,~~March 31, 2019, Puget Energy was in compliance with all applicable covenants.

Long-Term Debt

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 ~~3.7~~3.6 to 1.0 for the twelve months ended ~~June 30, 2018.~~March 31, 2019.

At ~~June 30, 2018,~~March 31, 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 Item I of this report.

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. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents.

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 increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to ~~$129.2~~$130.9 million and ~~$127.6~~$130.7 million as of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017,~~2018, respectively. ~~However, the~~The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. 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 ~~will accelerate~~has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

OnIn 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 onin September ~~20,~~ 2016. OnIn 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~~paid a penalty of $1.5 million in 2017, and is currently implementing a comprehensive inspection and remediation program. ~~However, litigation is still pending regarding damage and personal injury claims.~~

Regional Haze Rule

OnIn January ~~10,~~ 2017, the ~~EPA provided~~U.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. ~~Aspects~~In January 2018, EPA announced that it was reconsidering certain aspects of these revisions ~~are currently being challenged by various entities nationwide~~ and PSE is unable to predict the outcome.

Clean Air Act 111(d)/EPA Clean Power Plan

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule onin October ~~23,~~ 2015. OnIn March ~~31,~~ 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, onin October ~~10,~~ 2017, the EPA proposed to repeal the CPP rule.

In August 2018, the EPA proposed the Affordable Clean Energy rule to replace the 2015 Clean Power Plan. The ~~EPA is now reportedly developing a replacement CPP~~Affordable Clean Energy establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. Public comment closed on the proposed rule ~~for Section 111(d)~~in October 2018 and ~~it is expected sometime in the third quarter of 2018.~~ PSE ~~is still monitoring these developments and~~ cannot yet predict a final outcome.

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.

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. ~~On December 15, 2017,~~In March 2018, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March ~~2018.~~16, 2019, but no

determination by the court has yet been made. The federal court litigation ~~currently is stayed~~has been held in abeyance pending resolution of the state case.

Related Party Transactions

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

The Tacoma LNG facility is currently under construction. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of ~~June 30, 2018,~~March 31, 2019, Puget LNG has incurred ~~$144.7~~$176.0 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. 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, ~~2017.~~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 ~~June 30, 2018~~March 31, 2019, 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

~~In May~~During 2018, ~~Puget Energy~~PE implemented ~~a financial systems modernization project designed to improve~~internal controls covering the ~~financial processes, tools~~evaluation and ~~methods used throughout our business. The new/updated systems were used in preparing financial information for the three and six months ended June 30, 2018. Management monitored developments~~assessment of leasing contracts related to the financial systems modernization project, including working with the project team to ensure control impacts around the consolidation process were identified and documented, in order to assist management in evaluating impact to related internal controls. System integration and user acceptance testing were completed to aid management in its evaluations. Additionally, post-implementation reviewsadoption of the ~~system implementation and impacted business processes were conducted to enable management to evaluate the design and effectiveness~~new leasing standard as of ~~internal controls around the consolidations process during the period.~~January 1, 2019.

~~Except as previously described, there~~There have been no changes in Puget ~~Energy's~~Energy’s internal control over financial reporting during the quarter ended ~~June 30, 2018~~March 31, 2019 that have materially affected, or are reasonably likely to materially affect, ~~its~~Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of ~~June 30, 2018~~March 31, 2019, 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

~~In May~~During 2018, Puget 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 three and six months ended June 30, 2018. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts around the consolidation process were identified and documented, in order to assist management in evaluating impact to related internal controls. System integration and user acceptance testing were completed to aid management in its evaluations. Additionally, post-implementation reviews of the system implementation and impacted business processes were conducted to enable management to evaluate the design and effectiveness of internal controls around the consolidations process during the period.

~~During 2017,~~ PSE implemented internal controls covering the evaluation and assessment of ~~revenue~~leasing contracts related to the adoption of the new ~~revenue recognition~~leasing standard as of January 1, ~~2018.~~2019.

~~Except as previously described, there~~There have been no changes in ~~PSE's~~PSE’s internal control over financial reporting during the quarter ended ~~June 30, 2018~~March 31, 2019 that have materially affected, or are reasonably likely to materially affect, ~~PSE's~~PSE’s internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of ~~June 30, 2018~~March 31, 2019. Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitments and Contingencies" in the Combined Notes to Consolidated Financial Statements in Item I.

Item 1A. Risk Factors

There have been 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, ~~2017.~~2018.

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).
~~4.1~~10.1	~~Fifth Supplemental Indenture from~~Term Loan Agreement, dated as of October 1, 2018, by and among Puget ~~Sound~~ Energy, ~~Inc. to U.S Bank National Association, dated May 23, 2018~~Toronto Dominion (Texas) LLC, as Administrative Agent, TD Securities (USA) LLC, as Lead Arranger and Bookrunner and the lenders party thereto. (incorporated by reference to Exhibit ~~4.1~~410.1 to Puget Sound Energy's Current Report on Form 8-K Commission File No. 1-4393).
~~4.2~~	Purchase Agreement, dated June 4, 2018, between Puget Sound Energy, Inc. and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC and each of the other underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
12.1*	~~Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2013 through 2017 and 6 months ended June 30, 2018).~~
12.2*	~~Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2013 through 2017 and the 6 months ended June 30, 2018)~~.
31.1*	Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*	Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*	Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended ~~June 30, 2018~~March 31, 2019 filed on ~~August 1, 2018~~April 30, 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:	~~August~~May 1, ~~2018~~2019

6357



Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
March 31, 2018	Wells Hydro	$	4,302	$	2,395	$	1,907



Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)¹
Natural Gas:
2016	$47.4