10-Q

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 March 31, 2019

OR

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

For the Transition period from ________ to ________

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

1-16305 PUGET ENERGY, INC. A Washington Corporation 355 110th Ave NE Bellevue, Washington 98004 (425) 454-6363 91-1969407

1-4393 PUGET SOUND ENERGY, INC. A Washington Corporation 355 110th Ave NE Bellevue, Washington 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Puget Energy, Inc. Yes /X/ No /  / Puget Sound Energy, Inc. Yes /X/ No /  /

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer", "accelerated filer," a smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Puget Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated filer	/X/	Smaller reporting company	/  /	Emerging growth company	/  /
Puget Sound Energy, Inc.	Large accelerated filer	/  /	Accelerated filer	/  /	Non-accelerated filer	/X/	Smaller reporting company	/  /	Emerging growth company	/  /

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. / /

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Puget Energy, Inc. Yes /  / No /X/ Puget Sound Energy, Inc. Yes /  / No /X/

All of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.  All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.

Table of Contents

		Page
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 Months Ended March 31, 2018 and 2018	5
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2019 and 2018	6
	Consolidated Balance Sheets – March 31, 2019 and December 31, 2018	7
	Consolidated Statements of Common Shareholder's Equity - March 31, 2019 and 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 Months Ended March 31, 2019 and 2018	10
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2019 and 2018	11
	Consolidated Balance Sheets – March 31, 2019 and December 31, 2018	12
	Consolidated Statements of Common Shareholder's Equity - March 31, 2019 and December 31, 2018	14
	Consolidated Statements of Cash Flows – Three Months Ended March 30, 2019 and 2018	15
	Notes
	Combined Notes to Consolidated Financial Statements	16
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	54
Item 4.	Controls and Procedures
Part II.	Other Information	55
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 6.	Exhibits	55
Exhibit Index		56
Signatures		57

2

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.

3

FILING FORMAT

This report on Form 10-Q is a Quarterly Report filed separately by two registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE).  Any references in this report to “the Company” are to Puget Energy and PSE collectively.

FORWARD-LOOKING STATEMENTS

Puget Energy and PSE include the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE.  This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance.  Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.

Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed.  There can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.  

In addition to other factors and matters discussed elsewhere in this report, some important risks that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and those discussed in the forward-looking statements include:

● Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;

● Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

● Changes in tax law, related regulations or differing interpretation, including as a result of the TCJA, or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;

● Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;

● Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;

● 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, 2018.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Operating revenue:
Electric	$	798,928		$	699,686
Natural gas	304,668			330,284
Other	11,243			8,038
Total operating revenue	1,114,839			1,038,008
Operating expenses:
Energy costs:
Purchased electricity	270,702			154,206
Electric generation fuel	77,199			42,423
Residential exchange	(25,163		)	(23,943		)
Purchased natural gas	99,387			127,615
Unrealized (gain) loss on derivative instruments, net	(15,187		)	(996		)
Utility operations and maintenance	157,955			160,524
Non-utility expense and other	13,757			12,830
Depreciation and amortization	180,697			184,512
Conservation amortization	33,286			36,864
Taxes other than income taxes	108,746			111,188
Total operating expenses	901,379			805,223
Operating income (loss)	213,460			232,785
Other income (expense):
Other income	13,564			13,455
Other expense	(1,776		)	(2,098		)
Interest charges:
AFUDC	3,350			2,884
Interest expense	(88,016		)	(88,326		)
Income (loss) before income taxes	140,582			158,700
Income tax (benefit) expense	8,428			11,803
Net income (loss)	$	132,154		$	146,897

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

5

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2019		2018
Net income (loss)	$	132,154	$	146,897
Other comprehensive income (loss):
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		)
Other comprehensive income (loss)	92		(5,003		)
Comprehensive income (loss)	$	132,246	$	141,894

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

6

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS
	March 31, 2019			December 31, 2018
Utility plant (at original cost, including construction work in progress of $552,670 and $550,466 respectively):
Electric plant	$	8,594,886		$	8,515,482
Natural gas plant	3,665,783			3,598,732
Common plant	1,035,356			1,027,023
Less: Accumulated depreciation and amortization	(2,929,245		)	(2,832,321		)
Net utility plant	10,366,780			10,308,916
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	256,708			244,444
Total other property and investments	1,913,221			1,900,957
Current assets:
Cash and cash equivalents	20,818			37,521
Restricted cash	42,221			18,041
Accounts receivable, net of allowance for doubtful accounts of $10,358 and $8,408, respectively	415,725			338,782
Unbilled revenue	176,440			205,285
Purchased gas adjustment receivable	137,092			9,921
Materials and supplies, at average cost	120,243			116,180
Fuel and natural gas inventory, at average cost	40,161			53,351
Unrealized gain on derivative instruments	52,910			46,507
Prepaid expense and other	31,638			25,674
Power contract acquisition adjustment gain	6,888			6,114
Total current assets	1,044,136			857,376
Other long-term and regulatory assets:
Power cost adjustment mechanism	19,123			4,735
Regulatory assets related to power contracts	16,267			16,693
Other regulatory assets	688,072			773,552
Unrealized gain on derivative instruments	4,725			2,512
Power contract acquisition adjustment gain	154,629			156,597
Operating lease right of use asset	169,114			—
Other	78,909			77,523
Total other long-term and regulatory assets	1,130,839			1,031,612
Total assets	$	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
	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
Retained earnings	725,163			629,003
Accumulated other comprehensive income (loss), net of tax	(77,110		)	(77,202		)
Total common shareholder’s equity	3,957,010			3,860,758
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,764,412
Pollution control bonds	161,860			161,860
Long-term debt	1,975,300			1,961,900
Debt discount, issuance costs and other	(212,661		)	(215,681		)
Total long-term debt	5,688,911			5,672,491
Total capitalization	9,645,921			9,533,249
Current liabilities:
Accounts payable	505,623			480,069
Short-term debt	432,000			379,297
Accrued expenses:
Taxes	129,252			118,112
Salaries and wages	32,170			50,785
Interest	80,196			70,099
Unrealized loss on derivative instruments	32,452			46,661
Power contract acquisition adjustment loss	2,537			2,547
Operating lease liabilities	13,876			—
Other	109,504			79,312
Total current liabilities	1,337,610			1,226,882
Other long-term and regulatory liabilities:
Deferred income taxes	809,799			789,297
Unrealized loss on derivative instruments	7,184			11,095
Regulatory liabilities	756,339			747,203
Regulatory liability for deferred income taxes	966,898			975,974
Regulatory liabilities related to power contracts	161,517			162,711
Power contract acquisition adjustment loss	13,730			14,146
Operating lease liabilities	160,786			—
Other deferred credits	595,192			638,304
Total other long-term and regulatory liabilities	3,471,445			3,338,730
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	14,454,976		$	14,098,861

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

7

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

	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.

8

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.

9

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Operating revenue:
Electric	$	798,928		$	699,686
Natural gas	304,668			330,284
Other	11,243			8,038
Total operating revenue	1,114,839			1,038,008
Operating expenses:
Energy costs:
Purchased electricity	270,702			154,206
Electric generation fuel	77,199			42,423
Residential exchange	(25,163		)	(23,943		)
Purchased natural gas	99,387			127,615
Unrealized (gain) loss on derivative instruments, net	(15,187		)	(996		)
Utility operations and maintenance	157,955			160,524
Non-utility expense and other	13,077			9,781
Depreciation and amortization	180,678			184,490
Conservation amortization	33,286			36,864
Taxes other than income taxes	108,746			111,188
Total operating expenses	900,680			802,152
Operating income (loss)	214,159			235,856
Other income (expense):
Other income	10,549			7,641
Other expense	(1,776		)	(2,098		)
Interest charges:
AFUDC	3,350			2,884
Interest expense	(60,150		)	(59,555		)
Income (loss) before income taxes	166,132			184,728
Income tax (benefit) expense	18,830			21,691
Net income (loss)	$	147,302		$	163,037

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

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2019		2018
Net income (loss)	$	147,302	$	163,037
Other comprehensive income (loss):
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		)
Other comprehensive income (loss)	2,606		(24,374		)
Comprehensive income (loss)	$	149,908	$	138,663

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

11

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	March 31, 2019			December 31, 2018
Utility plant (at original cost, including construction work in progress of $552,670 and $550,466 respectively):
Electric plant	$	10,663,316		$	10,587,231
Natural gas plant	4,230,411			4,164,489
Common plant	1,060,623			1,052,544
Less:  Accumulated depreciation and amortization	(5,587,570		)	(5,495,348		)
Net utility plant	10,366,780			10,308,916
Other property and investments:
Other property and investments	79,128			76,986
Total other property and investments	79,128			76,986
Current assets:
Cash and cash equivalents	19,948			35,452
Restricted cash	42,221			18,041
Accounts receivable, net of allowance for doubtful accounts of $10,358 and $8,408, respectively	418,492			346,251
Unbilled revenue	176,440			205,285
Purchased gas adjustment receivable	137,092			9,921
Materials and supplies, at average cost	120,243			116,180
Fuel and natural gas inventory, at average cost	38,838			52,028
Unrealized gain on derivative instruments	52,910			46,507
Prepaid expense and other	31,638			25,674
Total current assets	1,037,822			855,339
Other long-term and regulatory assets:
Power cost adjustment mechanism	19,123			4,735
Other regulatory assets	688,072			773,552
Unrealized gain on derivative instruments	4,725			2,512
Operating lease right of use asset	169,114			—
Other	77,002			75,483
Total other long-term and regulatory assets	958,036			856,282
Total assets	$	12,441,766		$	12,097,523

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

12

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	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
Additional paid-in capital	3,275,105			3,275,105
Retained earnings	705,542			622,844
Accumulated other comprehensive income (loss), net of tax	(188,278		)	(190,884		)
Total common shareholder’s equity	3,793,228			3,707,924
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,764,417
Pollution control bonds	161,860			161,860
Debt discount, issuance costs and other	(31,007		)	(31,417		)
Total long-term debt	3,895,265			3,894,860
Total capitalization	7,688,493			7,602,784
Current liabilities:
Accounts payable	505,636			480,195
Short-term debt	432,000			379,297
Accrued expenses:
Taxes	131,643			117,993
Salaries and wages	32,170			50,785
Interest	56,903			43,951
Unrealized loss on derivative instruments	32,452			46,661
Operating lease liabilities	13,876			—
Other	109,504			79,312
Total current liabilities	1,314,184			1,198,194
Other long-term and regulatory liabilities:
Deferred income taxes	955,277			926,403
Unrealized loss on derivative instruments	7,184			11,095
Regulatory liabilities	755,016			745,880
Regulatory liability for deferred income taxes	967,694			976,582
Operating lease liabilities	160,786			—
Other deferred credits	593,132			636,585
Total other long-term and regulatory liabilities	3,439,089			3,296,545
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	12,441,766		$	12,097,523

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

13

 PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)

	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.

14

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Operating activities:
Net income (loss)	$	147,302		$	163,037
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	180,678			184,490
Conservation amortization	33,286			36,864
Deferred income taxes and tax credits, net	19,293			19,505
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	1,109			1,131
Funding of pension liability	—			(4,500		)
Regulatory assets and liabilities	(15,838		)	20,871
Other long-term assets and liabilities	(11,959		)	(9,844		)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(19,711		)	41,558
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	45,714			(27,973		)
Taxes payable	13,650			24,515
Other	8,006			(10,694		)
Net cash provided by (used in) operating activities	231,607			420,854
Investing activities:
Construction expenditures – excluding equity AFUDC	(218,006		)	(221,099		)
Other	264			1,570
Net cash provided by (used in) investing activities	(217,742		)	(219,529		)
Financing activities:
Change in short-term debt, net	52,703			41,226
Dividends paid	(64,604		)	(58,611		)
Redemption of bonds and notes	—			(193,447		)
Other	6,712			(1,529		)
Net cash provided by (used in) financing activities	(5,189		)	(212,361		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	8,676			(11,036		)
Cash, cash equivalents, and restricted cash at beginning of period	53,493			36,009
Cash, cash equivalents, and restricted cash at end of period	$	62,169		$	24,973
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	43,181		$	52,847
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.

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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 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 are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with 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 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. Per this allocation of costs, $175.7 million of construction work in progress and $0.3 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of March 31, 2019. Additionally, $139.7 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item, as 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.

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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

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 ASC and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842". In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019.

In July 2018, the FASB issued both ASU 2018-10 and ASU 2018-11, "Leases (Topic 842): Codification Improvements" and "Leases (Topic 842): Targeted Improvements". These ASUs provide entities with both clarification on existing guidance issued in ASU 2016-02, as well as an additional transition method to adopt the new leasing standard. Under the new transition method, the entity initially applies the new standard at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements will continue to be in accordance with Topic 840. The Company has elected to adopt the standard using this new modified transition method.

In preparation for adoption of the standard, the Company assembled a project team that met bi-weekly to make key accounting assessments and perform pre-implementation controls related to the scoping and completeness of existing leases. Additionally, the Company implemented a new leasing system and drafted accounting policies including discount rate, variable pricing, power purchase agreements, and election of practical expedients. In addition to the land easement practical expedient, the Company has elected the practical expedient package.

These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has adopted ASU 2016-02 as of January 1, 2019, which resulted in the recognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the income statement. The financial impact as of the date of adoption was not materially different than what has been disclosed as of March 31, 2019, in Note 9, "Leases", to the consolidated financial statements included in Item 1 of this report.

17

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.

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(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 March 31,
Revenue from contracts with customers:	2019			2018
Electric retail	$	637,189		$	630,806
Natural gas retail	322,560			334,033
Other	135,696			42,434
Total revenue from contracts with customers	1,095,445			1,007,273
Alternative revenue programs	(25,231		)	(15,081		)
Other non-customer revenue	44,625			45,816
Total operating revenue	$	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 sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

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

Electric Transmission and Natural Gas Transportation Revenue

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

Biogas Revenue

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

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

Wholesale Revenue

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

Other Revenue

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

(4) Accounting for Derivative Instruments and Hedging Activities

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

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

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

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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 March 31, 2019					December 31, 2018
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	37,728	$	16,538	*	$	33,287	$	27,284
Natural gas derivatives (MMBtus)3	316.3 million	19,907		23,098		336.6 million	15,732		30,472
Total derivative contracts		$	57,635	$	39,636		$	49,019	$	57,756
Current		$	52,910	$	32,452		$	46,507	$	46,661
Long-term		4,725		7,184			2,512		11,095
Total derivative contracts		$	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.

³  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 199.9 million One Million British Thermal Units (MMBtu) and purchased electricity of 10.1 million Megawatt Hours (MWhs) at March 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 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
	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
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	57,635	$	—	$	57,635	$	(29,907	)	$	—	$	27,728
Liabilities:
Energy derivative contracts	39,636		—		39,636		(29,907		)	—		9,729

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Puget Energy and Puget Sound Energy
	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
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	49,019	$	—	$	49,019	$	(25,388	)	$	—	$	23,631
Liabilities:
Energy derivative contracts	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 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 March 31, 2019, approximately 95.6% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 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

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weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2019, PSE had cash posted as collateral of $20.3 million related to contracts executed on the ICE platform. Also, as of March 31, 2019, PSE had $12.3 million in cash collateral and a letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended 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 March 31, 2019						At December 31, 2018
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	1,442	$	—	$	1,442	$	574	$	—	$	574
Requested credit for adequate assurance	5,175		—		—		18,495		—		—
Total	$	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.

(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

23

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 $49.6 million and $49.5 million at March 31, 2019 and December 31, 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 March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	5,513,611		6,698,705		5,510,591		6,443,742
Long-term debt (variable-rate)	2	175,300		175,300		161,900		161,900
Total liabilities		$	5,688,911	$	6,874,005	$	5,672,491	$	6,605,642

Puget Sound Energy		At March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	3,895,265		4,819,290		3,894,860		4,574,611
Total liabilities		$	3,895,265	$	4,819,290	$	3,894,860	$	4,574,611

_______________

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

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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
Puget Sound Energy	At March 31, 2019						At December 31, 2018
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	29,849	$	7,879	$	37,728	$	28,765	$	4,522	$	33,287
Natural gas derivative instruments	15,738		4,169		19,907		12,247		3,485		15,732
Total assets	$	45,587	$	12,048	$	57,635	$	41,012	$	8,007	$	49,019
Liabilities:
Electric derivative instruments	$	13,671	$	2,867	$	16,538	$	24,124	$	3,160	$	27,284
Natural gas derivative instruments	21,687		1,411		23,098		28,660		1,812		30,472
Total liabilities	$	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	Three Months Ended March 31,
Puget Sound Energy
(Dollars in Thousands)	2019									2018
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,362		$	1,673		$	3,035		$	1,098		$	1,923		$	3,021
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	12,325			—			12,325			1,619			—			1,619
Included in regulatory assets / liabilities	—			1,897			1,897			—			4,976			4,976
Settlements	(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	417			686			1,103			809			—			809
Balance at end of period	$	5,012		$	2,758		$	7,770		$	1,186		$	5,096		$	6,282

_______________

^1.  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $2.0 million for the three months ended March 31, 2019 and 2018, respectively.

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

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable, as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-Forward tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. The Company does periodically transact at locations or market price points that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for forward market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

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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 March 31, 2019:

Puget Energy and	Fair Value						Range
Puget Sound Energy
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	7,879	$	2,867	Discounted cash flow	Power prices (per MWh)	$	20.12	$	72.30	$	38.88
Natural gas	$	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, 2018:

Puget Energy and	Fair Value						Range
Puget Energy Sound
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,522	$	3,160	Discounted cash flow	Power prices (per MWh)	$	11.35	$	66.45	$	29.63
Natural gas	$	3,485	$	1,812	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.84	$	5.80	$	3.18

____________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of March 31, 2019 and December 31, 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 $5.7 million and $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 recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.

As of March 31, 2019, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy.

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(6) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  Starting 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 International Brotherhood of Electrical Workers (IBEW), participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also 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. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.

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

Puget 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	(12,624		)	(12,559		)	—		—		(97		)	(117		)
Amortization of prior service cost	(495		)	(495		)	83		11		—			—
Amortization of net loss (gain)	251			462			341		394		(63		)	(86		)
Net periodic benefit cost	$	(365	)	$	(387	)	$	1,258	$	1,147	$	(32	)	$	(76	)

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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 March 31, 2019 and December 31, 2018:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Three Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended
(Dollars in Thousands)	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	$	677,643		$	700,481		$	55,708		$	55,754		$	10,636		$	11,454
Amendments	—			—			—			1,446			—			—
Service cost	5,287			22,757			256			847			16			69
Interest cost	7,216			27,303			578			2,120			112			444
Actuarial loss (gain)	—			(29,067		)	—			1,122			—			(379		)
Benefits paid	(10,925		)	(42,662		)	(503		)	(5,581		)	(262		)	(1,037		)
Medicare part D subsidy received	—			—			—			—			—			85
Administrative Expense	—			(1,169		)	—			—			—			—
Benefit obligation at end of period	$	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, 2019 are expected to be at least $18.0 million, $6.2 million and $0.2 million, respectively. During the three months ended 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. The Company contributed an immaterial amount to fund the other postretirement plans.

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(7) Regulation and Rates

Expedited Rate Filing

On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million annual increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the 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 the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas and $25.9 million for electric. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC:

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 its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in the test year of the filing. The 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 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 one year period beginning May 1, 2019.

Washington Commission Tax Deferral Filing

The 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 new corporate tax rate.  PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform.  The requested deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas.

The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

As a result of the Washington Commission’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.

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Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

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

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

On 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.

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 three months ended March 31, 2019, PSE incurred $38.4 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $1.1 million and $26.4 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $5.7 million incurred in storm-related electric transmission and distribution system restoration costs for the three months ended March 31, 2018, of which 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.

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(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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, 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 $130.9 million and $130.7 million as of March 31, 2019, and December 31, 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 has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

In March 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 in September 2016. In March 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE paid a penalty of $1.5 million and is currently implementing a comprehensive inspection and remediation program.

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.

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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.} 

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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)
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

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Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
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 10K for the year ended December 31, 2018.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2018. 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 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 (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.

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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 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 2019 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly, under existing modified historical ratemaking, 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.

Expedited Rate Filing

On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Commission approved the 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.

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

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate.  PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform.  The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35% to 21%.

The Washington Commission approved the following PSE requests to change rates to reflect the new corporate tax rates:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
Electric:
May 1, 2018	(3.4)%	$(72.9)
Natural Gas:
May 1, 2018	(2.7)	(23.6)

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. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate cap which limits the amount of previously deferred revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism is to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

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

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.

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

Effective Date	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)
Natural Gas:
May 1, 2019	(5.3)%	$(45.9)
May 1, 2018	1.7	15.9

_______________

¹  There were no excess earnings for either electric or natural for the rates effective May 1, 2019. The increase in revenue is net of reductions from excess earnings of $10.0 million for electric and $4.9 million for natural gas effective May 1, 2018.

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

In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The deferral period requested was January 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC.  In November 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.

For the three months ended March 31, 2019, in its PCA mechanism, PSE under recovered its power costs by $43.1 million of which $14.3 million amount was apportioned to customers.  This compares to an over recovery of power costs of $7.5 million for the three months ended March 31, 2018 of which no amounts were apportioned to customers. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing an under collection compared to the prior year. Actual power costs were less than baseline rates in 2018 which caused an over collection. Load increased 4.2% year over year which is one driver of increased power cost. This was 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 transmission line contributed to a liquidity crisis at Mid-C, resulting in high market power prices; and 4) The relative prices of natural gas and power reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.

Electric Conservation Rider

The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to

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

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

Effective Date	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)

Electric Property Tax Tracker Mechanism

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	(0.2)%	$(5.1)
May 1, 2018	(0.1)	(1.3)

Federal Incentive Tracker Tariff

The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1. 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)
January 1, 2019	0.1%	$(38.7)
May 1, 2018	0.4	(40.1)
January 1, 2018	0.2	(48.2)

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Natural Gas Rates

Natural Gas Conservation Rider

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

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

Effective 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

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	(0.2)%	$(1.6)
May 1, 2018	(0.2)	(2.2)

Natural Gas Cost Recovery Mechanism

The purpose of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. Rates change annually on November 1.

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

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

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Purchased Gas Adjustment

PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. Rates typically change annually on November 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)
May 1, 2019	6.3%	$54.0
November 1, 2018	(10.9)	(98.4)

Other Proceedings

Large Customer Retail Wheeling

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

Voluntary Long-Term Renewable Energy

Effective September 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product. This provides customers with electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000 MWh) and government customers. The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW that will be constructed in the region by a developer under contract to PSE to meet the demand for this voluntary renewable energy product. 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.

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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.

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 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 March 31, 2018 and 2019:

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

Three months ended March 31, 2018 compared to 2019

Electric Operating Revenue

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

• Electric retail sales decreased $12.5 million due to a decrease in rates of $34.9 million, offset by an increase of $22.3 million from additional retail electricity usage of 3.3% compared to the prior year. The additional usage was due to an increase of residential and commercial use per customer of 5.2% and 0.9%, respectively, which was driven by an increase in heating degree days of 3.4% and an increase in retail customers of 1.4% compared to 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 utilities increased $15.8 million due to a 12.8% increase in volumes 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 115.7% increase in electric wholesale prices due to sustained cold weather leading to increased demand and regional gas supply constraints.

• Decoupling revenue decreased $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 allowed ROR were trued up to match actual earnings in excess of allowed ROR by $1.5 million.

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• Transportation and other revenue increased $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 decrease in production tax credit (PTC) deferral revenue of $16.5 million for the re-purpose of the 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 an 11% decrease in sales volume and a $29.8 million increase in the total cost of the non-core gas sold due to an approximately 141% increase in the average price of 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 increased $150.1 million primarily due to an increase of $116.5 million of purchased electricity costs and an increase of $34.8 million of electric generation fuel expense. These items are discussed in detail below.

• Purchased electricity expense increased $116.5 million primarily due to a 77.5% increase in wholesale prices and partially offset by a 1.1% decrease in wholesale electricity purchases. Spot power prices at Mid-Columbia hit an 18-year high largely driven by record-breaking natural gas prices and sustained cold weather.

• Electric generation fuel expense increased $34.8 million primarily due to a $32.9 million increase in combustion turbine generation costs primarily driven by an increase in generation of 111.8% as a result of favorable heat rates and reduced wind and hydro production. Additionally, all-time high natural gas prices at Sumas, which were largely due to regional natural gas supply constraints and cold weather leading to increased demand and increased fuel costs.

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Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through increases or decreases in the natural gas supply portion of the natural gas service rates to customers based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's margin or net income is not affected by changes under the PGA mechanism because over- and under- recoveries of natural gas costs included in baseline PGA rates are deferred and either refunded 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 March 31, 2018 and 2019:

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

Three months ended March 31, 2018 compared to 2019

Natural Gas Operating Revenue

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

• Natural gas retail sales revenue decreased $20.9 million due to a decrease in rates of $44.8 million, offset by an increase in natural gas sales of $23.9 million, which is a result of an increase in natural gas load of 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 PGA rates of 10.9%, a 2.7% decrease due to lower corporate tax rates resulting from the TCJA, and was offset by a 1.7% increase in decoupling rates. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 2 of this report for natural gas rate changes.

• Decoupling revenue decreased $2.6 million. This is primarily attributable to a lower allowed rate per customer and

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increased usage, as noted above in the retail revenue section. This resulted in allowed natural gas revenues being closer to actual natural gas revenues in the current year than in prior year.

• Other decoupling revenue decreased $11.2 million, primarily 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 $3.4 million.

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

Natural Gas Energy Costs

Purchased natural gas expense decreased $28.2 million due to a decrease in natural gas costs included in PGA rates partially offset by an increase in natural gas usage of 5.1%.

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 March 31, 2018 and 2019:

Three months ended March 31, 2018 compared to 2019

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments increased $14.2 million to a net gain of 15.2 million. The primary drivers for the increase in gains was due to an increase in the weighted average electricity and natural gas forward prices of 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 $2.6 million primarily due to a decrease in low income assistance

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funding expense.

• Non-utility expense and other increased $3.3 million due to an increase in long-term incentive plan expense of $1.8 million and an increase in biogas purchase expense of $1.4 million.

• Depreciation and amortization expense decreased $7.4 million primarily driven by: (i) a decrease in amortization of PTC regulatory liability of $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 $2.2 million, primarily due to net asset additions to distribution of $237.5 million; (iii) an increase of $10.1 million due to net additions of $236.3 million of computer software; and (iv) an increase in natural gas depreciation expense of $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 $2.4 million primarily due to decreases in municipal taxes of $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    

• Other Income/expense increased $3.2 million primarily due to a $1.3 million increase in the 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 this document.

• Income tax expense decreased $2.9 million primarily driven by a decrease in pre-tax income.

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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 March 31, 2018 and 2019 are as follows:

Three months ended March 31, 2018 compared to 2019

Summary Results of Operation

Puget Energy’s net income decreased for the three months ended March 31, 2019 by $14.7 million primarily due to a decrease over the prior year for PSE's net income.

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Capital Requirements

Contractual Obligations and Commercial Commitments

During the three months ended 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 Form 10-K for the period ended December 31, 2018.

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

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

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

Off-Balance Sheet Arrangements

As of 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 meet regulatory requirements, support customer growth and to improve energy system reliability.  Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $218.0 million for the three months ended March 31, 2019. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

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

The program is subject to change based upon general business, economic and regulatory conditions.  Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources which may include cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  

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Capital Resources

Cash from Operations

Puget Sound Energy	Three Months Ended March 31,
(Dollars in Millions)	2019			2018			Change
Net income	$	147,302		$	163,037		$	(15,735	)
Non-cash items1	188,451			194,057			(5,606		)
Changes in cash flow resulting from working capital2	(76,349		)	57,233			(133,582		)
Regulatory assets and liabilities	(15,838		)	20,871			(36,709		)
Other noncurrent assets and liabilities3	(11,959		)	(14,344		)	2,385
Net cash provided by operating activities	$	231,607		$	420,854		$	(189,247	)

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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.

Three Months Ended March 31, 2019 compared to 2018

Cash generated from operations for the three months ended March 31, 2019 decreased by $189.2 million including a net income decrease of $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 $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 power gas adjustments of $144.8 million.

• Cash flows resulting from regulatory assets and liabilities decreased $36.7 million primarily due to increases in revenue subject to refund and the power cost adjustment mechanism in 2018 compared to 2019.

Puget Energy	Three Months Ended March 31,
(Dollars in Millions)	2019			2018			Change
Net income	$	(15,148	)	$	(16,140	)	$	992
Non-cash items1	(5,260		)	(2,377		)	(2,883		)
Changes in cash flow resulting from working capital2	(11,498		)	300			(11,798		)
Regulatory assets and liabilities	—			—			—
Other noncurrent assets and liabilities3	(1,504		)	(3,316		)	1,812
Net cash provided by operating activities	$	(33,410	)	$	(21,533	)	$	(11,877	)

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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.

Three Months Ended March 31, 2019 compared to 2018

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

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

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Financing Program

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

Proceeds from PSE’s short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs.  Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

Puget Sound Energy

Credit Facility

As of 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 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 March 31, 2019, no amounts were drawn and outstanding under PSE's credit facility and $432.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $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 March 31, 2019, PSE had no outstanding balance under the Note.

Debt Restrictive Covenants

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

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

• Approximately $2.3 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $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 March 31, 2019; and

• Approximately $614.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $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 March 31, 2019.

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At March 31, 2019, PSE had approximately $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 March 31, 2019, approximately $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 44.5% at March 31, 2019 and the EBITDA to interest expense was 5.4 to 1.0 for the twelve months ended 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 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 March 31, 2019, there was $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 March 31, 2019, Puget Energy was in compliance with all applicable covenants.

Long-Term Debt

In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans 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.

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.6 to 1.0 for the twelve months ended March 31, 2019.

At March 31, 2019, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

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Other

New Accounting Pronouncements

For the discussion of new accounting pronouncements, see Note 2, "New Accounting Pronouncements" 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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, 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 $130.9 million and $130.7 million as of March 31, 2019 and December 31, 2018, respectively. 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 has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

In March 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 in September 2016. In March 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE paid a penalty of $1.5 million in 2017, and is currently implementing a comprehensive inspection and remediation program.

Regional Haze Rule

In January 2017, the U.S. Environmental Protection Agency (EPA) published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome.

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 in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 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 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 in October 2018 and PSE cannot yet predict a final outcome.

Washington Clean Air Rule

The CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019, but no

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determination by the court has yet been made. The federal court litigation 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 March 31, 2019, Puget LNG has incurred $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, 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 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.

54

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 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

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

There have been no changes in Puget Energy’s internal control over financial reporting during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

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

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

There have been no changes in PSE’s internal control over financial reporting during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

PART II                  OTHER INFORMATION

Item 1.     Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of 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, 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.

55

EXHIBIT INDEX

3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
10.1	Term Loan Agreement, dated as of October 1, 2018, by and among Puget Energy, 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 410.1 to Puget Sound Energy's Current Report on Form 8-K Commission File No. 1-4393).
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 March 31, 2019 filed on 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.

56

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:	May 1, 2019

57

EX-12.1

										Exhibit 12.1
PUGET ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	12 Months
	Ended			Years Ended
	March 31,			December 31,
	2018			2017			2016			2015			2014
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	315,185		$	430,337		$	453,103		$	332,954		$	228,820
AFUDC - equity	(16,720		)	(15,027		)	(12,576		)	(9,325		)	(7,002		)
AFUDC - debt	(13,085		)	(10,826		)	(9,304		)	(7,575		)	(5,611		)
Total	$	285,380		$	404,484		$	431,223		$	316,054		$	216,207
Fixed charges:
Interest expense (a)	$	351,019		$	354,802		$	355,139		$	356,696		$	367,308
Other interest	16,720			15,027			12,576			9,325			7,002
Portion of rentals representative of the interest factor (b)	8,071			8,062			8,061			8,980			10,732
Total	$	375,810		$	377,891		$	375,776		$	375,001		$	385,042
Earnings available for combined fixed charges	$	661,190		$	782,375		$	806,999		$	691,055		$	601,249
Ratio of Earnings to Fixed Charges	1.76x			2.07x			2.15x			1.84x			1.56x

(a) Interest expense for the year ended December 31, 2017 has been restated from the previously reported $343.9M.

(b) Represents interest portion of rents estimated at 33 1/3 percent.

EX-12.2

										Exhibit 12.2
PUGET SOUND ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	12 Months
	Ended			Years Ended
	March 31,			December 31,
	2019			2017			2016			2015			2014
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	420,818		$	532,040		$	555,928		$	430,089		$	325,955
AFUDC - equity	(16,720		)	(15,027		)	(12,576		)	(9,325		)	(7,002		)
AFUDC - debt	(13,085		)	(10,826		)	(9,304		)	(7,575		)	(5,611		)
Total	$	391,013		$	506,187		$	534,048		$	413,189		$	313,342
Fixed charges:
Interest expense (a)	$	234,676		$	240,144		$	242,983		$	247,571		$	264,926
Other interest	16,720			15,027			12,576			9,325			7,002
Portion of rentals representative of the interest factor (b)	8,071			8,062			8,061			8,980			10,732
Total	$	259,467		$	263,233		$	263,620		$	265,876		$	282,660
Earnings available for combined fixed charges	$	650,480		$	769,420		$	797,668		$	679,065		$	596,002
Ratio of Earnings to Fixed Charges	2.51x			2.92x			3.03x			2.55x			2.11x

(a) Interest expense for the year ended December 31, 2017 has been restated from the previously reported $229.3M.

(b) Represents interest portion of rents estimated at 33 1/3 percent.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2019

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-Q of Puget Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2019

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Kimberly J. Harris, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2019

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Daniel A. Doyle, certify that:

I have reviewed this report on Form 10-Q of Puget Sound Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

May 1, 2019

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period endedMarch 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Kimberly J. Harris, President and Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

May 1, 2019

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Puget Energy, Inc. and Puget Sound Energy, Inc. (the “Companies”) on Form 10-Q for the period endedMarch 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), I, Daniel A. Doyle, Senior Vice President and Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Companies.

May 1, 2019

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

XML

Document And Entity Information	3 Months Ended
	Mar. 31, 2019 shares
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Entity Emerging Growth Company	false
Entity Small Business	false
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Entity Emerging Growth Company	false
Entity Small Business	false

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating revenue:
Electric	$ 798,928	$ 699,686
Natural gas	304,668	330,284
Other	11,243	8,038
Total operating revenue	1,114,839	1,038,008
Energy costs:
Purchased electricity	270,702	154,206
Electric generation fuel	77,199	42,423
Residential exchange	(25,163)	(23,943)
Purchased natural gas	99,387	127,615
Unrealized (gain) loss on derivative instruments, net	(15,187)	(996)
Utility operations and maintenance	157,955	160,524
Non-utility expense and other	13,757	12,830
Depreciation and amortization	180,697	184,512
Conservation amortization	33,286	36,864
Taxes other than income taxes	108,746	111,188
Total operating expenses	901,379	805,223
Operating income (loss)	213,460	232,785
Other income (expense):
Other income	13,564	13,455
Other expense	(1,776)	(2,098)
Interest charges:
AFUDC	3,350	2,884
Interest expense	(88,016)	(88,326)
Income (loss) before income taxes	140,582	158,700
Income tax (benefit) expense	8,428	11,803
Net income (loss)	132,154	146,897
Subsidiaries [Member]
Operating revenue:
Electric	798,928	699,686
Natural gas	304,668	330,284
Other	11,243	8,038
Total operating revenue	1,114,839	1,038,008
Energy costs:
Purchased electricity	270,702	154,206
Electric generation fuel	77,199	42,423
Residential exchange	(25,163)	(23,943)
Purchased natural gas	99,387	127,615
Unrealized (gain) loss on derivative instruments, net	(15,187)	(996)
Utility operations and maintenance	157,955	160,524
Non-utility expense and other	13,077	9,781
Depreciation and amortization	180,678	184,490
Conservation amortization	33,286	36,864
Taxes other than income taxes	108,746	111,188
Total operating expenses	900,680	802,152
Operating income (loss)	214,159	235,856
Other income (expense):
Other income	10,549	7,641
Other expense	(1,776)	(2,098)
Interest charges:
AFUDC	3,350	2,884
Interest expense	(60,150)	(59,555)
Income (loss) before income taxes	166,132	184,728
Income tax (benefit) expense	18,830	21,691
Net income (loss)	$ 147,302	$ 163,037

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net income (loss)	$ 132,154	$ 146,897
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	92	227
Reclassification of stranded taxes to retained earnings due to tax reform	0	(5,230)
Other comprehensive income (loss)	92	(5,003)
Comprehensive income (loss)	132,246	141,894
Subsidiaries [Member]
Net income (loss)	147,302	163,037
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	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	0	(27,333)
Other comprehensive income (loss)	2,606	(24,374)
Comprehensive income (loss)	$ 149,908	$ 138,663

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 25	$ 60
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	668	761
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 26

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively):
Electric plant	$ 8,594,886	$ 8,515,482
Natural gas plant	3,665,783	3,598,732
Common plant	1,035,356	1,027,023
Less: Accumulated depreciation and amortization	(2,929,245)	(2,832,321)
Net utility plant	10,366,780	10,308,916
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	256,708	244,444
Total other property and investments	1,913,221	1,900,957
Current assets:
Cash and cash equivalents	20,818	37,521
Restricted cash	42,221	18,041
Accounts receivable, net of allowance for doubtful accounts	415,725	338,782
Unbilled revenue	176,440	205,285
Purchased gas adjustment receivable	137,092	9,921
Materials and supplies, at average cost	120,243	116,180
Fuel and gas inventory, at average cost	40,161	53,351
Unrealized gain on derivative instruments	52,910	46,507
Prepaid expense and other	31,638	25,674
Power contract acquisition adjustment gain	6,888	6,114
Total current assets	1,044,136	857,376
Other long-term and regulatory assets:
Power cost adjustment mechanism	19,123	4,735
Regulatory assets related to power contracts	16,267	16,693
Other regulatory assets	688,072	773,552
Derivative Asset, Noncurrent	4,725	2,512
Power contract acquisition adjustment gain	154,629	156,597
Operating lease right of use asset	169,114	0
Other	78,909	77,523
Total other long-term and regulatory assets	1,130,839	1,031,612
Total assets	14,454,976	14,098,861
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	725,163	629,003
Accumulated other comprehensive income (loss), net of tax	(77,110)	(77,202)
Total common shareholder's equity	3,957,010	3,860,758
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,764,412
Pollution control bonds	161,860	161,860
Long-term debt	1,975,300	1,961,900
Debt discount, issuance costs and other	(212,661)	(215,681)
Total long-term debt	5,688,911	5,672,491
Total capitalization	9,645,921	9,533,249
Current liabilities:
Accounts payable	505,623	480,069
Short-term debt	432,000	379,297
Accrued expenses:
Taxes	129,252	118,112
Salaries and wages	32,170	50,785
Interest	80,196	70,099
Unrealized loss on derivative instruments	32,452	46,661
Power contract acquisition adjustment loss	2,537	2,547
Operating lease liabilities	13,876	0
Other	109,504	79,312
Total current liabilities	1,337,610	1,226,882
Long-term and regulatory liabilities:
Deferred income taxes	809,799	789,297
Unrealized loss on derivative instruments	7,184	11,095
Regulatory liabilities	756,339	747,203
Regulatory liability for deferred income taxes	966,898	975,974
Regulatory liabilities related to power contracts	161,517	162,711
Power contract acquisition adjustment loss	13,730	14,146
Operating lease liabilities	160,786	0
Other deferred credits	595,192	638,304
Total long-term and regulatory liabilities	3,471,445	3,338,730
Commitments and contingencies (Note 8)
Total capitalization and liabilities	14,454,976	14,098,861
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively):
Electric plant	10,663,316	10,587,231
Natural gas plant	4,230,411	4,164,489
Common plant	1,060,623	1,052,544
Less: Accumulated depreciation and amortization	(5,587,570)	(5,495,348)
Net utility plant	10,366,780	10,308,916
Other property and investments:
Other property and investments	79,128	76,986
Total other property and investments	79,128	76,986
Current assets:
Cash and cash equivalents	19,948	35,452
Restricted cash	42,221	18,041
Accounts receivable, net of allowance for doubtful accounts	418,492	346,251
Unbilled revenue	176,440	205,285
Purchased gas adjustment receivable	137,092	9,921
Materials and supplies, at average cost	120,243	116,180
Fuel and gas inventory, at average cost	38,838	52,028
Unrealized gain on derivative instruments	52,910	46,507
Prepaid expense and other	31,638	25,674
Total current assets	1,037,822	855,339
Other long-term and regulatory assets:
Power cost adjustment mechanism	19,123	4,735
Other regulatory assets	688,072	773,552
Derivative Asset, Noncurrent	4,725	2,512
Operating lease right of use asset	169,114	0
Other	77,002	75,483
Total other long-term and regulatory assets	958,036	856,282
Total assets	12,441,766	12,097,523
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Earnings reinvested in the business	705,542	622,844
Accumulated other comprehensive income (loss), net of tax	(188,278)	(190,884)
Total common shareholder's equity	3,793,228	3,707,924
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,764,417
Pollution control bonds	161,860	161,860
Debt discount, issuance costs and other	(31,007)	(31,417)
Total long-term debt	3,895,265	3,894,860
Total capitalization	7,688,493	7,602,784
Current liabilities:
Accounts payable	505,636	480,195
Short-term debt	432,000	379,297
Accrued expenses:
Taxes	131,643	117,993
Salaries and wages	32,170	50,785
Interest	56,903	43,951
Unrealized loss on derivative instruments	32,452	46,661
Operating lease liabilities	13,876	0
Other	109,504	79,312
Total current liabilities	1,314,184	1,198,194
Long-term and regulatory liabilities:
Deferred income taxes	955,277	926,403
Unrealized loss on derivative instruments	7,184	11,095
Regulatory liabilities	755,016	745,880
Regulatory liability for deferred income taxes	967,694	976,582
Operating lease liabilities	160,786	0
Other deferred credits	593,132	636,585
Total long-term and regulatory liabilities	3,439,089	3,296,545
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$ 12,441,766	$ 12,097,523

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
ASSETS
Construction work in progress	$ 552,670	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 10,358	$ 8,408
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 552,670	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 10,358	$ 8,408
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common Stock, Shares, Outstanding	85,903,791	85,903,791

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Parent [Line Items]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 63,039	$ 25,803
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)
Monetized production tax credits	(27,131)	(43,586)
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities	3,722	3,720
Funding of pension liability	0	(4,500)
Regulatory Assets	(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)
Increase (Decrease) in Fuel Inventories	(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)
Dividends, Common Stock	35,994	30,096
Proceeds from long-term debt and bonds issued	13,400	13,179
Redemption of bonds and notes	0	(193,447)
Other	6,714	(1,530)
Net cash provided by (used in) financing activities	36,823	(170,668)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	7,477	(10,958)
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
Subsidiaries [Member]
Parent [Line Items]
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	62,169	24,973
Operating activities:
Net income (loss)	147,302	163,037
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	180,678	184,490
Conservation amortization	33,286	36,864
Deferred income taxes and tax credits, net	19,293	19,505
Net unrealized (gain) loss on derivative instruments	(15,187)	(996)
AFUDC – equity	(3,597)	(3,351)
Monetized production tax credits	(27,131)	(43,586)
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities	1,109	1,131
Funding of pension liability	0	(4,500)
Regulatory Assets	(15,838)	20,871
Other long-term assets and liabilities	(11,959)	(9,844)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(19,711)	41,558
Materials and supplies	(4,063)	(1,825)
Increase (Decrease) in Fuel Inventories	(13,190)	(15,543)
Prepayments and other	(5,964)	(1,503)
Purchased gas adjustment	(127,171)	17,612
Accounts payable	45,714	(27,973)
Taxes payable	13,650	24,515
Other	8,006	(10,694)
Net cash provided by (used in) operating activities	231,607	420,854
Investing activities:
Construction expenditures - excluding equity AFUDC	(218,006)	(221,099)
Other	264	1,570
Net cash provided by (used in) investing activities	(217,742)	(219,529)
Financing activities:
Change in short-term debt, net	52,703	41,226
Dividends paid	(64,604)	(58,611)
Dividends, Common Stock	64,604	58,611
Redemption of bonds and notes	0	(193,447)
Other	6,712	(1,529)
Net cash provided by (used in) financing activities	(5,189)	(212,361)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	8,676	(11,036)
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	43,181	52,847
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$ 77,400	$ 90,169

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Subsidiaries [Member]	Subsidiaries [Member] Common Stock [Member]	Subsidiaries [Member] Additional Paid-in Capital [Member]	Subsidiaries [Member] Retained Earnings [Member]	Subsidiaries [Member] AOCI Attributable to Parent [Member]
Common Stock, Shares, Outstanding at Dec. 31, 2017		200,000					85,903,791
Stockholders' Equity Attributable to Parent at Dec. 31, 2017	$ 3,750,030		$ 3,308,957	$ 465,355	$ (24,282)	$ 3,601,124	$ 859	$ 3,275,105	$ 452,066	$ (126,906)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	146,897					163,037
Payments of Dividends	30,096			(30,096)		58,611
Common stock dividend paid	(30,096)					(58,611)
Common stock dividend paid	(5,003)				(5,003)	(24,374)				(24,374)
Cumulative effect of accounting change	5,230			5,230		27,333			27,333
Common Stock, Shares, Outstanding at Mar. 31, 2018		200,000					85,903,791
Stockholders' Equity Attributable to Parent at Mar. 31, 2018	$ 3,867,058		3,308,957	587,386	(29,285)	$ 3,708,509	$ 859	3,275,105	583,825	(151,280)
Common Stock, Shares, Outstanding at Dec. 31, 2018	200	200,000				85,903,791	85,903,791
Stockholders' Equity Attributable to Parent at Dec. 31, 2018	$ 3,860,758		3,308,957	629,003	(77,202)	$ 3,707,924	$ 859	3,275,105	622,844	(190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	132,154					147,302
Payments of Dividends	35,994			(35,994)		64,604
Common stock dividend paid	(35,994)					(64,604)
Common stock dividend paid	$ 92				92	$ 2,606				2,606
Common Stock, Shares, Outstanding at Mar. 31, 2019	200	200,000				85,903,791	85,903,791
Stockholders' Equity Attributable to Parent at Mar. 31, 2019	$ 3,957,010		$ 3,308,957	$ 725,163	$ (77,110)	$ 3,793,228	$ 859	$ 3,275,105	$ 705,542	$ (188,278)

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Summary of Consolidation Policy

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Summary of Consolidation 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 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 are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with 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 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. Per this allocation of costs, $175.7 million of construction work in progress and $0.3 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of March 31, 2019. Additionally, $139.7 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item, as 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.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Recently Adopted Accounting Guidance

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing 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 ASC and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842". In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019.

In July 2018, the FASB issued both ASU 2018-10 and ASU 2018-11, "Leases (Topic 842): Codification Improvements" and "Leases (Topic 842): Targeted Improvements". These ASUs provide entities with both clarification on existing guidance issued in ASU 2016-02, as well as an additional transition method to adopt the new leasing standard. Under the new transition method, the entity initially applies the new standard at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements will continue to be in accordance with Topic 840. The Company has elected to adopt the standard using this new modified transition method.

In preparation for adoption of the standard, the Company assembled a project team that met bi-weekly to make key accounting assessments and perform pre-implementation controls related to the scoping and completeness of existing leases. Additionally, the Company implemented a new leasing system and drafted accounting policies including discount rate, variable pricing, power purchase agreements, and election of practical expedients. In addition to the land easement practical expedient, the Company has elected the practical expedient package.

These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company has adopted ASU 2016-02 as of January 1, 2019, which resulted in the recognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the income statement. The financial impact as of the date of adoption was not materially different than what has been disclosed as of March 31, 2019, in Note 9, "Leases", to the consolidated financial statements included in Item 1 of this report.

Internal-Use Software

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

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

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.

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Revenue

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue

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 March 31,
Revenue from contracts with customers:	2019			2018
Electric retail	$	637,189		$	630,806
Natural gas retail	322,560			334,033
Other	135,696			42,434
Total revenue from contracts with customers	1,095,445			1,007,273
Alternative revenue programs	(25,231		)	(15,081		)
Other non-customer revenue	44,625			45,816
Total operating revenue	$	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 sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

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

Electric Transmission and Natural Gas Transportation Revenue

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

Biogas Revenue

Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered.

Wholesale Revenue

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

Other Revenue

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

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Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

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 March 31, 2019					December 31, 2018
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	37,728	$	16,538	*	$	33,287	$	27,284
Natural gas derivatives (MMBtus)3	316.3 million	19,907		23,098		336.6 million	15,732		30,472
Total derivative contracts		$	57,635	$	39,636		$	49,019	$	57,756
Current		$	52,910	$	32,452		$	46,507	$	46,661
Long-term		4,725		7,184			2,512		11,095
Total derivative contracts		$	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.

³  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 199.9 million One Million British Thermal Units (MMBtu) and purchased electricity of 10.1 million Megawatt Hours (MWhs) at March 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 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
	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
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	57,635	$	—	$	57,635	$	(29,907	)	$	—	$	27,728
Liabilities:
Energy derivative contracts	39,636		—		39,636		(29,907		)	—		9,729

Puget Energy and Puget Sound Energy
	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
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	49,019	$	—	$	49,019	$	(25,388	)	$	—	$	23,631
Liabilities:
Energy derivative contracts	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 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 March 31, 2019, approximately 95.6% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 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. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of March 31, 2019, PSE had cash posted as collateral of $20.3 million related to contracts executed on the ICE platform. Also, as of March 31, 2019, PSE had $12.3 million in cash collateral and a letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the three months ended 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 March 31, 2019						At December 31, 2018
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	1,442	$	—	$	1,442	$	574	$	—	$	574
Requested credit for adequate assurance	5,175		—		—		18,495		—		—
Total	$	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.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 $49.6 million and $49.5 million at March 31, 2019 and December 31, 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 March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	5,513,611		6,698,705		5,510,591		6,443,742
Long-term debt (variable-rate)	2	175,300		175,300		161,900		161,900
Total liabilities		$	5,688,911	$	6,874,005	$	5,672,491	$	6,605,642

Puget Sound Energy		At March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	3,895,265		4,819,290		3,894,860		4,574,611
Total liabilities		$	3,895,265	$	4,819,290	$	3,894,860	$	4,574,611

_______________

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At March 31, 2019						At December 31, 2018
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	29,849	$	7,879	$	37,728	$	28,765	$	4,522	$	33,287
Natural gas derivative instruments	15,738		4,169		19,907		12,247		3,485		15,732
Total assets	$	45,587	$	12,048	$	57,635	$	41,012	$	8,007	$	49,019
Liabilities:
Electric derivative instruments	$	13,671	$	2,867	$	16,538	$	24,124	$	3,160	$	27,284
Natural gas derivative instruments	21,687		1,411		23,098		28,660		1,812		30,472
Total liabilities	$	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	Three Months Ended March 31,
Puget Sound Energy
(Dollars in Thousands)	2019									2018
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,362		$	1,673		$	3,035		$	1,098		$	1,923		$	3,021
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	12,325			—			12,325			1,619			—			1,619
Included in regulatory assets / liabilities	—			1,897			1,897			—			4,976			4,976
Settlements	(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	417			686			1,103			809			—			809
Balance at end of period	$	5,012		$	2,758		$	7,770		$	1,186		$	5,096		$	6,282

_______________

^1.  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $2.0 million for the three months ended March 31, 2019 and 2018, respectively.

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

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable, as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-Forward tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. The Company does periodically transact at locations or market price points that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for forward market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2019:

Puget Energy and	Fair Value						Range
Puget Sound Energy
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	7,879	$	2,867	Discounted cash flow	Power prices (per MWh)	$	20.12	$	72.30	$	38.88
Natural gas	$	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, 2018:

Puget Energy and	Fair Value						Range
Puget Energy Sound
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,522	$	3,160	Discounted cash flow	Power prices (per MWh)	$	11.35	$	66.45	$	29.63
Natural gas	$	3,485	$	1,812	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.84	$	5.80	$	3.18

____________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of March 31, 2019 and December 31, 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 $5.7 million and $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 recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power.

As of March 31, 2019, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy.

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Retirement Benefits

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Retirement Benefits

Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  Starting 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 International Brotherhood of Electrical Workers (IBEW), participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also 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. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income.

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

Puget 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	(12,624		)	(12,559		)	—		—		(97		)	(117		)
Amortization of prior service cost	(495		)	(495		)	83		11		—			—
Amortization of net loss (gain)	251			462			341		394		(63		)	(86		)
Net periodic benefit cost	$	(365	)	$	(387	)	$	1,258	$	1,147	$	(32	)	$	(76	)

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 March 31, 2019 and December 31, 2018:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Three Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended
(Dollars in Thousands)	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	$	677,643		$	700,481		$	55,708		$	55,754		$	10,636		$	11,454
Amendments	—			—			—			1,446			—			—
Service cost	5,287			22,757			256			847			16			69
Interest cost	7,216			27,303			578			2,120			112			444
Actuarial loss (gain)	—			(29,067		)	—			1,122			—			(379		)
Benefits paid	(10,925		)	(42,662		)	(503		)	(5,581		)	(262		)	(1,037		)
Medicare part D subsidy received	—			—			—			—			—			85
Administrative Expense	—			(1,169		)	—			—			—			—
Benefit obligation at end of period	$	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, 2019 are expected to be at least $18.0 million, $6.2 million and $0.2 million, respectively. During the three months ended 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. The Company contributed an immaterial amount to fund the other postretirement plans.

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Regulation and Rates

3 Months Ended

Mar. 31, 2019

Regulation and Rates [Abstract]

Regulation and Rates

Regulation and Rates

Expedited Rate Filing

On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million annual increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the 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 the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas and $25.9 million for electric. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC:

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 its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in the test year of the filing. The 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 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 one year period beginning May 1, 2019.

Washington Commission Tax Deferral Filing

The 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 new corporate tax rate.  PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform.  The requested deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes.  Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas.

The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

As a result of the Washington Commission’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. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

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

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

On 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.

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 three months ended March 31, 2019, PSE incurred $38.4 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $1.1 million and $26.4 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $5.7 million incurred in storm-related electric transmission and distribution system restoration costs for the three months ended March 31, 2018, of which 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.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, 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 $130.9 million and $130.7 million as of March 31, 2019, and December 31, 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 has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

In March 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 in September 2016. In March 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE paid a penalty of $1.5 million and is currently implementing a comprehensive inspection and remediation program.

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.

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Leases (Notes)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases

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)
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)
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

Leases

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)
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)
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

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Other

3 Months Ended

Mar. 31, 2019

Other [Abstract]

Other

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 10K for the year ended December 31, 2018.

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Summary of Consolidation Policy (Policies)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Significant Accounting Policies

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 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 are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with 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 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. Per this allocation of costs, $175.7 million of construction work in progress and $0.3 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of March 31, 2019. Additionally, $139.7 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item, as 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.

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Revenue (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of 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 March 31,
Revenue from contracts with customers:	2019			2018
Electric retail	$	637,189		$	630,806
Natural gas retail	322,560			334,033
Other	135,696			42,434
Total revenue from contracts with customers	1,095,445			1,007,273
Alternative revenue programs	(25,231		)	(15,081		)
Other non-customer revenue	44,625			45,816
Total operating revenue	$	1,114,839		$	1,038,008

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Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2019

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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 March 31, 2019					December 31, 2018
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	37,728	$	16,538	*	$	33,287	$	27,284
Natural gas derivatives (MMBtus)3	316.3 million	19,907		23,098		336.6 million	15,732		30,472
Total derivative contracts		$	57,635	$	39,636		$	49,019	$	57,756
Current		$	52,910	$	32,452		$	46,507	$	46,661
Long-term		4,725		7,184			2,512		11,095
Total derivative contracts		$	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.

³  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 199.9 million One Million British Thermal Units (MMBtu) and purchased electricity of 10.1 million Megawatt Hours (MWhs) at March 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018.

Offsetting Assets and Liabilities

Puget Energy and Puget Sound Energy
	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
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	49,019	$	—	$	49,019	$	(25,388	)	$	—	$	23,631
Liabilities:
Energy derivative contracts	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 tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
	At March 31, 2019
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	57,635	$	—	$	57,635	$	(29,907	)	$	—	$	27,728
Liabilities:
Energy derivative contracts	39,636		—		39,636		(29,907		)	—		9,729

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

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

Puget Energy and Puget Sound Energy		Three Months Ended March 31,
(Dollars in Thousands)	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	)

Schedule of Credit Risk Related Contingent Features

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 March 31, 2019						At December 31, 2018
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	1,442	$	—	$	1,442	$	574	$	—	$	574
Requested credit for adequate assurance	5,175		—		—		18,495		—		—
Total	$	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.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Inputs, Liabilities, Quantitative Information

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 March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount1	2	5,513,611		6,698,705		5,510,591		6,443,742
Long-term debt (variable-rate)	2	175,300		175,300		161,900		161,900
Total liabilities		$	5,688,911	$	6,874,005	$	5,672,491	$	6,605,642

Puget Sound Energy		At March 31, 2019				At December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Long-term debt (fixed-rate), net of discount2	2	3,895,265		4,819,290		3,894,860		4,574,611
Total liabilities		$	3,895,265	$	4,819,290	$	3,894,860	$	4,574,611

_______________

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

Schedule of Fair Value, Assets and Liabilities Measured on 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
Puget Sound Energy	At March 31, 2019						At December 31, 2018
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	29,849	$	7,879	$	37,728	$	28,765	$	4,522	$	33,287
Natural gas derivative instruments	15,738		4,169		19,907		12,247		3,485		15,732
Total assets	$	45,587	$	12,048	$	57,635	$	41,012	$	8,007	$	49,019
Liabilities:
Electric derivative instruments	$	13,671	$	2,867	$	16,538	$	24,124	$	3,160	$	27,284
Natural gas derivative instruments	21,687		1,411		23,098		28,660		1,812		30,472
Total liabilities	$	35,358	$	4,278	$	39,636	$	52,784	$	4,972	$	57,756

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

Puget Energy and	Three Months Ended March 31,
Puget Sound Energy
(Dollars in Thousands)	2019									2018
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,362		$	1,673		$	3,035		$	1,098		$	1,923		$	3,021
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	12,325			—			12,325			1,619			—			1,619
Included in regulatory assets / liabilities	—			1,897			1,897			—			4,976			4,976
Settlements	(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	417			686			1,103			809			—			809
Balance at end of period	$	5,012		$	2,758		$	7,770		$	1,186		$	5,096		$	6,282

_______________

^1.  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $2.0 million for the three months ended March 31, 2019 and 2018, respectively.

Fair Value Inputs, Assets and Liabilities, Quantitative Information

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of March 31, 2019:

Puget Energy and	Fair Value						Range
Puget Sound Energy
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	7,879	$	2,867	Discounted cash flow	Power prices (per MWh)	$	20.12	$	72.30	$	38.88
Natural gas	$	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, 2018:

Puget Energy and	Fair Value						Range
Puget Energy Sound
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,522	$	3,160	Discounted cash flow	Power prices (per MWh)	$	11.35	$	66.45	$	29.63
Natural gas	$	3,485	$	1,812	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.84	$	5.80	$	3.18

____________

¹  The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2019

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

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

Puget 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	(12,624		)	(12,559		)	—		—		(97		)	(117		)
Amortization of prior service cost	(495		)	(495		)	83		11		—			—
Amortization of net loss (gain)	251			462			341		394		(63		)	(86		)
Net periodic benefit cost	$	(365	)	$	(387	)	$	1,258	$	1,147	$	(32	)	$	(76	)

Schedule of Changes in Projected Benefit Obligations

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

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Three Months Ended			Year Ended			Three Months Ended			Year Ended			Three Months Ended			Year Ended
(Dollars in Thousands)	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	$	677,643		$	700,481		$	55,708		$	55,754		$	10,636		$	11,454
Amendments	—			—			—			1,446			—			—
Service cost	5,287			22,757			256			847			16			69
Interest cost	7,216			27,303			578			2,120			112			444
Actuarial loss (gain)	—			(29,067		)	—			1,122			—			(379		)
Benefits paid	(10,925		)	(42,662		)	(503		)	(5,581		)	(262		)	(1,037		)
Medicare part D subsidy received	—			—			—			—			—			85
Administrative Expense	—			(1,169		)	—			—			—			—
Benefit obligation at end of period	$	679,221		$	677,643		$	56,039		$	55,708		$	10,502		$	10,636

Subsidiaries [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Net Benefit Costs

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	)

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Leases (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Schedule of lease cost

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.} 

Schedule of lease assets and liabilities

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		%

Schedule of maturity of operating lease liability

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)
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

Schedule of maturity of finance lease liability

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)
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

Schedule of future minimum lease payments

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
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

Schedule of future minimum lease payments

Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
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

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Summary of Consolidation Policy (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($) mi²	Mar. 31, 2018 USD ($)
Summary of Consolidation Policy
Non-utility expense and other	$ 13,757	$ 12,830
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000
Non-utility expense and other	$ 13,077	$ 9,781
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Construction in Progress, Gross	$ 139,700
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%
Construction in Progress, Gross	$ 175,700
Puget LNG [Member]
Summary of Consolidation Policy
Non-utility expense and other	$ 300

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New Accounting Pronouncements Stranded Taxes in AOCI (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
strandedtaxesinAOCI [Line Items]
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	$ 0	$ 5,230
Cumulative effect of accounting change		5,230
Subsidiaries [Member]
strandedtaxesinAOCI [Line Items]
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	$ 0	27,333
Cumulative effect of accounting change		$ 27,333

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New Accounting Pronouncements Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash and cash equivalents	$ 20,818	$ 37,521
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	63,039	55,562	$ 25,803	$ 36,761
Subsidiaries [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash and cash equivalents	19,948	35,452
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$ 62,169	$ 53,493	$ 24,973	$ 36,009

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 1,095,445	$ 1,007,273
Regulated Operating Revenue, Other	11,243	8,038
Total operating revenue	1,114,839	1,038,008
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	637,189	630,806
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	322,560	334,033
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	135,696	42,434
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	(25,231)	(15,081)
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	44,625	45,816
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	11,243	8,038
Total operating revenue	$ 1,114,839	$ 1,038,008

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Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions	3 Months Ended
	Mar. 31, 2019 MWh MMBTU	Dec. 31, 2018 MWh MMBTU
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	316.3	336.6
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	199.9	194.8
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh	10.1	6.6
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	$ 15,187	$ 996
Unrealized gain on derivative instruments	52,910		$ 46,507
Assets, Long-term	4,725		2,512
Derivative Liability, Current	32,452		46,661
Unrealized loss on derivative instruments	7,184		11,095
Subsidiaries [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	15,187	996
Unrealized gain on derivative instruments	52,910		46,507
Assets, Long-term	4,725		2,512
Derivative Liability, Current	32,452		46,661
Unrealized loss on derivative instruments	7,184		11,095
Commodity Contract [Member]
Derivative [Line Items]
Assets	57,635		49,019
Derivative Liability	39,636		57,756
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	64,807	(9,069)
Unrealized gain on derivative instruments	52,910		46,507
Assets, Long-term	4,725		2,512
Assets	57,635		49,019
Derivative Liability, Current	32,452		46,661
Derivative Liability	39,636		57,756
Unrealized loss on derivative instruments	7,184		11,095
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	37,728		33,287
Derivative Liability	16,538		27,284
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	19,907		15,732
Derivative Liability	23,098		$ 30,472
Not Designated as Hedging Instrument [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member] | Electricity, US Regulated [Member]
Derivative [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	$ 226	$ (1,316)

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Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) $ in Thousands, MMBTU in Millions	Mar. 31, 2019 USD ($) MMBTU		Dec. 31, 2018 USD ($) MMBTU
Derivative [Line Items]
Derivative Asset, Current	$ 52,910		$ 46,507
Derivative Liability, Current	32,452		46,661
Derivative Asset, Noncurrent	4,725		2,512
Derivative Liability, Noncurrent	7,184		11,095
Commodity Contract [Member]
Assets:
Gross Amount Recognized in the Statement of Financial Position	57,635	[1]	49,019
Gross Amounts Offset in the Statement of Financial Position	0		0
Assets	57,635		49,019
Commodity Contracts	(29,907)		(25,388)
Cash Collateral Received	0		0
Net Amount	27,728		23,631
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	39,636	[1]	57,756
Gross Amounts Offset in the Statement of Financial Position	0		0
Net of Amounts Presented in the Statement of Financial Position	39,636		57,756
Commodity Contracts	(29,907)		(25,388)
Cash Collateral Posted	0		0
Net Amount	9,729		32,368
Subsidiaries [Member]
Derivative [Line Items]
Derivative Asset, Current	52,910		46,507
Derivative Liability, Current	32,452		46,661
Derivative Asset, Noncurrent	4,725		2,512
Derivative Liability, Noncurrent	7,184		11,095
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Current	52,910		46,507
Derivative Liability, Current	32,452		46,661
Derivative Asset, Noncurrent	4,725		2,512
Derivative Liability, Noncurrent	7,184		11,095
Assets:
Assets	57,635		49,019
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	39,636		57,756
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Assets:
Assets	37,728		33,287
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	$ 16,538		$ 27,284
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	316.3		336.6
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Assets:
Assets	$ 19,907		$ 15,732
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	$ 23,098		$ 30,472

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

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Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (15,187)	$ (996)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(64,807)	9,069
Not Designated as Hedging Instrument [Member] | Electric generation fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(14,961)	(2,312)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(13,328)	7,676
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (36,292)	$ 2,389

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Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands		Mar. 31, 2019	Dec. 31, 2018
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		95.60%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		4.40%
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 6,617	$ 19,069
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		1,442	574
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	20,300
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	1,442	574
Posted Collateral	[2]	0	0
Additional Collateral, Aggregate Fair Value	[2]	1,442	574
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	[2]	12,300
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	5,175	18,495
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		$ 0	$ 0

[1] 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] 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.

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Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2019	Dec. 31, 2018
Liabilities:
Total long-term debt		$ 5,688,911	$ 5,672,491
Subsidiaries [Member]
Liabilities:
Total long-term debt		3,895,265	3,894,860
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		5,688,911	5,672,491
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	5,513,611	5,510,591
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[1]	175,300	161,900
Debt issuance costs	[1]	25,300	26,100
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		6,874,005	6,605,642
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	6,698,705	6,443,742
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[1]	175,300	161,900
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		3,895,265	3,894,860
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	3,895,265	3,894,860
Debt issuance costs	[1]	24,200	24,600
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		4,819,290	4,574,611
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	$ 4,819,290	$ 4,574,611

[1] 1 The carrying value includes debt issuances costs of $25.3 million and $26.1 million for March 31, 2019 and December 31, 2018, respectively, which are not included in fair value.

XML

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		$ 5,688,911		$ 5,672,491
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		3,035	$ 3,021
Included in earnings	[1]	12,325	1,619
Included in regulatory assets/liabilities		1,897	4,976
Settlements		(14,583)	(2,306)
Transferred into Level 3		3,993	(1,837)
Transferred out of Level 3		1,103	809
Balance at end of period		7,770	6,282
Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		3,100	2,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,362	1,098
Included in earnings	[1]	12,325	1,619
Included in regulatory assets/liabilities		0	0
Settlements		(13,483)	(503)
Transferred into Level 3		4,391	(1,837)
Transferred out of Level 3		417	809
Balance at end of period		5,012	1,186
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,673	1,923
Included in earnings	[1]	0	0
Included in regulatory assets/liabilities		1,897	4,976
Settlements		(1,100)	(1,803)
Transferred into Level 3		(398)	0
Transferred out of Level 3		686	0
Balance at end of period		2,758	$ 5,096
Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		3,895,265		3,894,860
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		57,635		49,019
Derivative Liability		39,636		57,756
Fair Value, Measurements, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		37,728		33,287
Derivative Liability		16,538		27,284
Fair Value, Measurements, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		19,907		15,732
Derivative Liability		23,098		30,472
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		45,587		41,012
Derivative Liability		35,358		52,784
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		29,849		28,765
Derivative Liability		13,671		24,124
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		15,738		12,247
Derivative Liability		21,687		28,660
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		12,048		8,007
Derivative Liability		4,278		4,972
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,879		4,522	[2]
Derivative Liability		2,867		3,160	[2]
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		4,169		3,485	[2]
Derivative Liability		1,411		1,812	[2]
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		49,600		49,500
Valuation, Income Approach [Member] | Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		5,688,911		5,672,491
Valuation, Income Approach [Member] | Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	5,513,611		5,510,591
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	175,300		161,900
Unamortized Debt Issuance Expense	[3]	25,300		26,100
Valuation, Income Approach [Member] | Carrying Value [Member] | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		3,895,265		3,894,860
Valuation, Income Approach [Member] | Carrying Value [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	3,895,265		3,894,860
Unamortized Debt Issuance Expense	[3]	24,200		24,600
Valuation, Income Approach [Member] | Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		6,874,005		6,605,642
Valuation, Income Approach [Member] | Total [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	6,698,705		6,443,742
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	175,300		161,900
Valuation, Income Approach [Member] | Total [Member] | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		4,819,290		4,574,611
Valuation, Income Approach [Member] | Total [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	$ 4,819,290		$ 4,574,611

[1] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjU2ZmE0ZDgzZjI1NDQ3M2U5ZmViZjVkMzU4ZjBhYmUzfFRleHRTZWxlY3Rpb246Qzc5RDcyNDY4OTIxNTNGMzhGQ0VFNUMwMkExMzkxRDgM}

[2] 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

[3] 1 The carrying value includes debt issuances costs of $25.3 million and $26.1 million for March 31, 2019 and December 31, 2018, respectively, which are not included in fair value.

XML

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019 USD ($) $ / MMBTU $ / MWh	Dec. 31, 2018 USD ($) $ / MMBTU $ / MWh
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 5,700	$ 2,600
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	57,635	49,019
Derivative Liability	$ 39,636	$ 57,756
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	20.12	11.35
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	72.30	66.45
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	38.88	29.63
Electric Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 37,728	$ 33,287
Derivative Liability	$ 16,538	$ 27,284
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU	0.72	1.84
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU	3.79	5.80
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU	2.71	3.18
Natural Gas Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 19,907	$ 15,732
Derivative Liability	$ 23,098	$ 30,472

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Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 5,287		$ 22,757
Interest cost	7,216		27,303
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	256		847
Interest cost	578		2,120
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	16		69
Interest cost	112		$ 444
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,287	$ 5,425
Interest cost	7,216	6,780
Expected return on plan assets	(12,624)	(12,559)
Amortization of prior service cost	(495)	(495)
Amortization of net loss (gain)	251	462
Net periodic benefit cost	(365)	(387)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	256	212
Interest cost	578	530
Expected return on plan assets	0	0
Amortization of prior service cost	83	11
Amortization of net loss (gain)	341	394
Net periodic benefit cost	1,258	1,147
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	16	17
Interest cost	112	110
Expected return on plan assets	(97)	(117)
Amortization of prior service cost	0	0
Amortization of net loss (gain)	(63)	(86)
Net periodic benefit cost	(32)	(76)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,287	5,425
Interest cost	7,216	6,780
Expected return on plan assets	(12,628)	(12,569)
Amortization of prior service cost	(393)	(393)
Amortization of net loss (gain)	3,165	3,630
Net periodic benefit cost	2,647	2,873
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	256	212
Interest cost	578	530
Expected return on plan assets	0	0
Amortization of prior service cost	83	11
Amortization of net loss (gain)	433	517
Net periodic benefit cost	1,350	1,270
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	16	17
Interest cost	112	110
Expected return on plan assets	(98)	(117)
Amortization of prior service cost	0	0
Amortization of net loss (gain)	(109)	(142)
Net periodic benefit cost	$ (79)	$ (132)

XML

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 677,643	$ 700,481
Service cost	5,287	22,757
Interest cost	7,216	27,303
Actuarial loss/(gain)	0	(29,067)
Benefits paid	(10,925)	(42,662)
Medicare part D subsidiary received	0	0
Administrative Expense	0	(1,169)
Benefit obligation at end of period	679,221	677,643
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	55,708	55,754
Service cost	256	847
Interest cost	578	2,120
Actuarial loss/(gain)	0	1,122
Benefits paid	(503)	(5,581)
Medicare part D subsidiary received	0	0
Administrative Expense	0	0
Benefit obligation at end of period	56,039	55,708
Other Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	10,636	11,454
Service cost	16	69
Interest cost	112	444
Actuarial loss/(gain)	0	(379)
Benefits paid	(262)	(1,037)
Medicare part D subsidiary received	0	85
Administrative Expense	0	0
Benefit obligation at end of period	10,502	10,636
Nonqualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	(1,446)
Qualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	$ 0	$ 0

XML

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended		11 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 12, 2014	Dec. 31, 2019
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer		$ 4.5
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.5	$ 0.6
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Additional Contribution of Base Pay, Percentage			4.00%
Defined Contribution Plan, Employer Matching Contribution, Percent			1.00%
Scenario, Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions				$ 18.0
Scenario, Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions				6.2
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions				$ 0.2

XML

Regulation and Rates (Details) - USD ($)							3 Months Ended		12 Months Ended
	Mar. 01, 2019	Nov. 07, 2018	May 01, 2018	Mar. 01, 2018	Dec. 19, 2017	Dec. 18, 2017	Mar. 31, 2019	Mar. 31, 2018	Apr. 30, 2019	Jan. 01, 2018
Regulatory Assets [Line Items]
Income tax (benefit) expense							$ 8,428,000	$ 11,803,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense			$ 34,600,000				18,830,000	21,691,000
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period							38,400,000	5,700,000
Storm Damage Costs Deferred During Period								0
Public Utilities, Rate Case, Deferred Storm Costs Threshold							8,000,000			$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs										$ 500,000
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					5.00%	3.00%
General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		7.49%			7.60%
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 18,900,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		0.90%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 0
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 21,700,000		$ 6,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		2.70%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 21,500,000			$ 25,900,000
Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period								$ 1,100,000
Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period							$ 26,400,000
Scenario, Forecast [Member] | Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount									$ (72,900,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage									(3.40%)
Scenario, Forecast [Member] | Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount									$ (23,600,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage									(2.70%)

XML

Commitments and Contingencies (Details) $ in Millions	Mar. 28, 2017 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value	$ 1.5
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)		50.00%
Jointly Owned Utility Plant		2
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)		25.00%
Colstrip Regulatory Asset [Domain]
Loss Contingencies [Line Items]
Regulatory Assets		$ 130.9	$ 130.7

XML

Leases (Details)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Remaining lease term (less than)	26 years
Lessee, lease, renewal term (up to)	25 years

XML

Leases - Schedule of the components of lease expense (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Related Party Transaction [Line Items]
Amortization of right-of-use asset	$ 158
Interest on lease liabilities	9
Total finance lease cost	167
Operating lease cost	4,784
Land | Subsidiaries
Related Party Transaction [Line Items]
Operating lease cost	$ 300

XML

Leases - Supplemental cash flow information related to leases (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Leases [Abstract]
Operating cash flows from operating leases	$ (4,346)
Investing cash flow from operating leases	(438)
Operating cash flow from finance leases	(9)
Financing cash flows from finances leases	(158)
Related Party Transaction [Line Items]
Investing cash flow from operating leases	438
Land | Subsidiaries
Leases [Abstract]
Investing cash flow from operating leases	(300)
Related Party Transaction [Line Items]
Investing cash flow from operating leases	$ 300

XML

Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Operating Leases
Operating lease right-of-use asset	$ 169,114	$ 0
Operating leases liabilities current	(13,876)	0
Operating lease liabilities long-term	(160,786)	$ 0
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 years 7 months 28 days
Finance leases	3 years 7 days
Weighted Average Discount Rate
Operating leases	3.78%
Finance leases	2.97%

XML

Leases - Schedule of future minimyn lease payments (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Operating Leases
2019	$ 15,505
2020	20,672
2021	20,598
2022	20,171
2023	19,213
Thereafter	132,889
Total lease payments	229,048
Less imputed interest	(54,386)
Total	174,662
Finance Leases
2019	430
2020	511
2021	376
2022	147
2023	11
Thereafter	0
Total lease payments	1,475
Less imputed interest	(58)
Total	$ 1,417

XML

Leases - Schedule of future minimum lease payments (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Operating Leases
2019	$ 20,635
2020	20,704
2021	20,630
2022	20,202
2023	19,223
Thereafter	132,889
Total minimum lease payments	234,283
Finance Leases
2019	495
2020	446
2021	311
2022	82
2023	0
Thereafter	0
Total minimum lease payments	$ 1,334

XML

Other (Details) $ in Millions	Apr. 01, 2019 USD ($)
Subsequent Event [Member] | Term Loan Expansion [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 24.0