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 June 30, 2018

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 10885 NE 4^th Street, Suite 1200 Bellevue, Washington 98004-5591 (425) 454-6363 91-1969407

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

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

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

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

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

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

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

Table of Contents

		Page
Definitions		3
Filing Format		4
Forward-Looking Statements		4
Part I.	Financial Information	5
Item 1.	Financial Statements	5
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2018 and 2017	5
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2018 and 2017	6
	Consolidated Balance Sheets – June 30, 2018 and December 31, 2017	7
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2018 and 2017	8
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2018 and 2017	9
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2018 and 2017	10
	Consolidated Balance Sheets – June 30, 2018 and December 31, 2017	11
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2018 and 2017	13
	Notes
	Combined Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	59
Item 4.	Controls and Procedures	60
Part II.	Other Information	61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 6.	Exhibits	61
Exhibit Index		62
Signatures		63

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
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, 2017.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Operating revenue:
Electric	$	501,510		$	529,807		$	1,201,196		$	1,198,792
Natural gas	160,196			180,105			490,480			580,169
Other	10,146			9,855			18,184			18,038
Total operating revenue	671,852			719,767			1,709,860			1,796,999
Operating expenses:
Energy costs:
Purchased electricity	129,114			129,799			283,320			309,381
Electric generation fuel	29,750			34,163			72,173			85,473
Residential exchange	(16,091		)	(15,121		)	(40,035		)	(38,568		)
Purchased natural gas	53,872			63,183			181,487			215,984
Unrealized (gain) loss on derivative instruments, net	(6,911		)	3,834			(7,907		)	23,121
Utility operations and maintenance	140,131			145,555			300,655			297,618
Non-utility expense and other	8,419			6,144			21,249			11,339
Depreciation and amortization	152,105			119,457			336,617			234,710
Conservation amortization	24,025			25,691			60,888			60,453
Taxes other than income taxes	73,347			77,032			184,535			195,731
Total operating expenses	587,761			589,737			1,392,982			1,395,242
Operating income (loss)	84,091			130,030			316,878			401,757
Other income (expense):
Other income	8,116			6,263			21,573			12,223
Other expense	(2,330		)	(2,042		)	(4,428		)	(3,257		)
Non-hedged interest rate swap (expense) income	—			—			—			28
Interest charges:
AFUDC	3,318			2,555			6,201			4,730
Interest expense	(86,084		)	(88,409		)	(174,410		)	(176,991		)
Income (loss) before income taxes	7,111			48,397			165,814			238,490
Income tax (benefit) expense	3,469			13,122			15,272			75,665
Net income (loss)	$	3,642		$	35,275		$	150,542		$	162,825

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

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

6

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS
	June 30, 2018			December 31, 2017
Utility plant (at original cost, including construction work in progress of $637,322 and $495,937, respectively):
Electric plant	$	8,305,168		$	8,135,847
Natural gas plant	3,444,954			3,307,545
Common plant	905,018			811,815
Less: Accumulated depreciation and amortization	(2,623,659		)	(2,428,524		)
Net utility plant	10,031,481			9,826,683
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	222,170			182,355
Total other property and investments	1,878,683			1,838,868
Current assets:
Cash and cash equivalents	8,117			26,616
Restricted cash	10,083			10,145
Accounts receivable, net of allowance for doubtful accounts of $10,716 and $8,901, respectively	218,306			341,110
Unbilled revenue	123,214			222,186
Materials and supplies, at average cost	112,913			107,003
Fuel and natural gas inventory, at average cost	51,084			49,908
Unrealized gain on derivative instruments	19,872			22,247
Prepaid expense and other	23,418			21,996
Power contract acquisition adjustment gain	8,480			12,207
Total current assets	575,487			813,418
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651			4,576
Regulatory assets related to power contracts	17,754			19,454
Other regulatory assets	818,081			948,532
Unrealized gain on derivative instruments	3,589			2,158
Power contract acquisition adjustment gain	159,168			162,711
Other	84,159			74,389
Total other long-term and regulatory assets	1,087,402			1,211,820
Total assets	$	13,573,053		$	13,690,789

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

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) CAPITALIZATION AND LIABILITIES
	June 30, 2018			December 31, 2017
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	565,600			465,355
Accumulated other comprehensive income (loss), net of tax	(29,059		)	(24,282		)
Total common shareholder’s equity	3,845,498			3,750,030
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,164,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	—			250,000
Long-term debt	1,939,551			1,902,600
Debt discount, issuance costs and other	(220,632		)	(220,943		)
Total long-term debt	5,645,191			5,257,929
Total capitalization	9,490,689			9,007,959
Current liabilities:
Accounts payable	308,305			359,586
Short-term debt	28,000			329,463
Current maturities of long-term debt	—			200,000
Purchased gas adjustment payable	38,645			16,051
Accrued expenses:
Taxes	104,092			117,948
Salaries and wages	42,180			53,220
Interest	69,564			73,564
Unrealized loss on derivative instruments	49,776			64,859
Power contract acquisition adjustment loss	2,585			2,762
Other	93,900			80,206
Total current liabilities	737,047			1,297,659
Other long-term and regulatory liabilities:
Deferred income taxes	774,195			746,868
Unrealized loss on derivative instruments	15,123			21,235
Regulatory liabilities	743,766			731,587
Regulatory liability for deferred income taxes	994,987			1,011,626
Regulatory liabilities related to power contracts	167,647			174,918
Power contract acquisition adjustment loss	15,169			16,693
Other deferred credits	634,430			682,244
Total other long-term and regulatory liabilities	3,345,317			3,385,171
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	13,573,053		$	13,690,789

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

7

PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)
	Six Months Ended June 30,
	2018			2017
Operating activities:
Net income (loss)	$	150,542		$	162,825
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	336,617			234,710
Conservation amortization	60,888			60,453
Deferred income taxes and tax credits, net	10,567			75,665
Net unrealized (gain) loss on derivative instruments	(7,907		)	22,980
AFUDC – equity	(7,146		)	(6,766		)
Production tax credit monetization	(51,181		)	—
Other non-cash	7,377			8,283
Funding of pension liability	(9,000		)	(18,000		)
Regulatory assets and liabilities	4,591			(46,101		)
Other long-term assets and liabilities	(12,611		)	4,281
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	220,207			196,179
Materials and supplies	(5,910		)	5,606
Fuel and natural gas inventory	(1,176		)	2,473
Prepayments and other	(1,422		)	13,900
Purchased gas adjustment	22,594			13,765
Accounts payable	(47,040		)	(49,478		)
Taxes payable	(13,856		)	(9,296		)
Other	(16,937		)	(5,809		)
Net cash provided by (used in) operating activities	639,197			665,670
Investing activities:
Construction expenditures – excluding equity AFUDC	(490,623		)	(496,652		)
Other	1,956			(6,642		)
Net cash provided by (used in) investing activities	(488,667		)	(503,294		)
Financing activities:
Change in short-term debt, net	(301,463		)	(240,763		)
Dividends paid	(55,525		)	(132		)
Proceeds from long-term debt and bonds issued	631,701			48,073
Redemption of bonds and notes	(450,000		)	—
Other	6,196			9,003
Net cash provided by (used in) financing activities	(169,091		)	(183,819		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(18,561		)	(21,443		)
Cash, cash equivalents, and restricted cash at beginning of period	36,761			41,296
Cash, cash equivalents, and restricted cash at end of period	$	18,200		$	19,853
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	164,823		$	163,228
Cash payments (refunds) for income taxes	5,169			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	97,614		$	54,419

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

8

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Operating revenue:
Electric	$	501,510		$	529,807		$	1,201,196		$	1,198,792
Natural gas	160,196			180,105			490,480			580,169
Other	10,146			9,855			18,184			18,038
Total operating revenue	671,852			719,767			1,709,860			1,796,999
Operating expenses:
Energy costs:
Purchased electricity	129,114			129,799			283,320			309,381
Electric generation fuel	29,750			34,163			72,173			85,473
Residential exchange	(16,091		)	(15,121		)	(40,035		)	(38,568		)
Purchased natural gas	53,872			63,183			181,487			215,984
Unrealized (gain) loss on derivative instruments, net	(6,911		)	3,834			(7,907		)	23,121
Utility operations and maintenance	140,131			145,555			300,655			297,618
Non-utility expense and other	10,834			9,374			20,614			17,865
Depreciation and amortization	152,080			119,457			336,570			234,710
Conservation amortization	24,025			25,691			60,888			60,453
Taxes other than income taxes	73,347			77,032			184,535			195,731
Total operating expenses	590,151			592,967			1,392,300			1,401,768
Operating income (loss)	81,701			126,800			317,560			395,231
Other income (expense):
Other income	8,113			6,126			15,756			12,086
Other expense	(2,330		)	(2,042		)	(4,428		)	(3,257		)
Interest charges:
AFUDC	3,318			2,555			6,201			4,730
Interest expense	(57,020		)	(59,991		)	(116,575		)	(120,453		)
Income (loss) before income taxes	33,782			73,448			218,514			288,337
Income tax (benefit) expense	7,004			22,794			28,696			94,591
Net income (loss)	$	26,778		$	50,654		$	189,818		$	193,746

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

9

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

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

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

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	June 30, 2018			December 31, 2017
Utility plant (at original cost, including construction work in progress of $637,322 and $495,937, respectively):
Electric plant	$	10,389,267		$	10,232,771
Natural gas plant	4,018,260			3,882,733
Common plant	935,706			843,145
Less:  Accumulated depreciation and amortization	(5,311,752		)	(5,131,966		)
Net utility plant	10,031,481			9,826,683
Other property and investments:
Other property and investments	77,109			76,350
Total other property and investments	77,109			76,350
Current assets:
Cash and cash equivalents	7,104			25,864
Restricted cash	10,083			10,145
Accounts receivable, net of allowance for doubtful accounts of $10,716 and $8,901, respectively	224,901			343,546
Unbilled revenue	123,214			222,186
Materials and supplies, at average cost	112,913			107,003
Fuel and natural gas inventory, at average cost	49,761			48,585
Unrealized gain on derivative instruments	19,872			22,247
Prepaid expense and other	23,418			21,996
Total current assets	571,266			801,572
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651			4,576
Other regulatory assets	818,081			948,540
Unrealized gain on derivative instruments	3,589			2,158
Other	81,862			71,827
Total other long-term and regulatory assets	908,183			1,027,101
Total assets	$	11,588,039		$	11,731,706

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

11

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

CAPITALIZATION AND LIABILITIES

	June 30, 2018			December 31, 2017
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	566,758			452,066
Accumulated other comprehensive income (loss), net of tax	(148,320		)	(126,906		)
Total common shareholder’s equity	3,694,402			3,601,124
Long-term debt:
First mortgage bonds and senior notes	3,764,412			3,164,412
Pollution control bonds	161,860			161,860
Junior subordinated notes	—			250,000
Debt discount, issuance costs and other	(31,230		)	(26,361		)
Total long-term debt	3,895,042			3,549,911
Total capitalization	7,589,444			7,151,035
Current liabilities:
Accounts payable	308,304			359,585
Short-term debt	28,000			329,463
Current maturities of long-term debt	—			200,000
Purchased gas adjustment payable	38,645			16,051
Accrued expenses:
Taxes	104,092			117,063
Salaries and wages	42,180			53,220
Interest	43,672			47,837
Unrealized loss on derivative instruments	49,776			64,859
Other	93,900			80,206
Total current liabilities	708,569			1,268,284
Other long-term and regulatory liabilities:
Deferred income taxes	906,226			869,473
Unrealized loss on derivative instruments	15,123			21,235
Regulatory liabilities	742,443			730,273
Regulatory liability for deferred income taxes	995,599			1,012,260
Other deferred credits	630,635			679,146
Total other long-term and regulatory liabilities	3,290,026			3,312,387
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	11,588,039		$	11,731,706

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

12

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30,
	2018			2017
Operating activities:
Net income (loss)	$	189,818		$	193,746
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	336,570			234,710
Conservation amortization	60,888			60,453
Deferred income taxes and tax credits, net	18,519			94,590
Net unrealized (gain) loss on derivative instruments	(7,907		)	23,121
AFUDC – equity	(7,146		)	(6,766		)
Production tax credit monetization	(51,181		)	—
Other non-cash	2,197			2,675
Funding of pension liability	(9,000		)	(18,000		)
Regulatory assets and liabilities	4,591			(46,101		)
Other long-term assets and liabilities	(5,956		)	(14,507		)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	216,047			205,327
Materials and supplies	(5,910		)	5,606
Fuel and natural gas inventory	(1,176		)	2,473
Prepayments and other	(1,422		)	13,900
Purchased gas adjustment	22,594			13,765
Accounts payable	(47,040		)	(49,478		)
Taxes payable	(12,971		)	(9,296		)
Other	(17,100		)	(6,542		)
Net cash provided by (used in) operating activities	684,415			699,676
Investing activities:
Construction expenditures – excluding equity AFUDC	(452,220		)	(431,536		)
Other	1,956			(6,205		)
Net cash provided by (used in) investing activities	(450,264		)	(437,741		)
Financing activities:
Change in short-term debt, net	(301,463		)	(240,763		)
Dividends paid	(102,456		)	(51,574		)
Long-term bonds and notes issued	594,750			—
Redemption of bonds and notes	(450,000		)	—
Other	6,196			9,003
Net cash provided by (used in) financing activities	(252,973		)	(283,334		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(18,822		)	(21,399		)
Cash, cash equivalents, and restricted cash at beginning of period	36,009			40,899
Cash, cash equivalents, and restricted cash at end of period	$	17,187		$	19,500
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	112,354		$	112,801
Cash payments (refunds) for income taxes	$	9,631		$	—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	97,614		$	54,419

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

13

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) 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 LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of June 30, 2018, Puget LNG has incurred $145.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. 

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 determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, 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. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

For Puget Energy, $144.7 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $113.4 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

(2)  New Accounting Pronouncements

Recently Adopted Accounting Guidance

Income Taxes

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

14

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

Stranded Tax Effects in AOCI

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

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

Retirement Benefits

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

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

Statement of Cash Flows

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

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

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

15

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

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

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

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". Accounting Standards Update (ASU) 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

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

Accounting Standards Issued but Not Yet Adopted

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification 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 leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019.

This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must

16

apply a modified retrospective approach for the adoption of the new standard.  The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets.

(3) Revenue

The following table presents disaggregated revenue from contracts with customers, and other revenue by major source:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Three Months Ended June 30,			Six Months Ended June 30,
Revenue from contracts with customers:	2018			2018
Electric retail	$	468,378		$	1,099,184
Natural gas retail	158,544			492,578
Other	38,930			81,364
Total revenue from contracts with customers	665,852			1,673,126
Alternative revenue programs	(8,815		)	(23,897		)
Other non-customer revenue	14,815			60,631
Total operating revenue	$	671,852		$	1,709,860

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

Other Revenue from Contracts with Customers

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

Electric Transmission and Natural Gas Transportation

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 gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the Federal Energy Regulatory Commission (FERC) and, therefore, corresponds directly to the value to the customer for performance completed to date.

17

Biogas

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

Wholesale Revenue

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

Other Revenue

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

(4) Accounting for Derivative Instruments and Hedging Activities

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

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

18

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

Puget Energy and Puget Sound Energy
	At June 30, 2018					At December 31, 2017
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	10,889	$	38,642	*	$	13,391	$	49,050
Natural gas derivatives (MMBtus)3	299.2 million	12,572		26,257		332.1 million	11,014		37,044
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094
Current		$	19,872	$	49,776		$	22,247	$	64,859
Long-term		3,589		15,123			2,158		21,235
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094

_______________

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 172.5 million One Million British Thermal Units (MMBtu) and purchased electricity of 3.7 million Megawatt Hours (MWhs) at June 30, 2018, and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017.

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.

19

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 June 30, 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	$	23,461	$	—	$	23,461	$	(17,120	)	$	—		$	6,341
Liabilities:
Energy derivative contracts	64,899		—		64,899		(17,120		)	(1,220		)	46,559

Puget Energy and Puget Sound Energy
	At December 31, 2017
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801

_______________

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

20

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

Puget Energy and Puget Sound Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Classification	2018			2017			2018			2017
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	—		$	—		$	28
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	5,357			(5,746		)	7,669			(21,882		)
Realized	Electric generation fuel	(4,417		)	(2,822		)	(12,093		)	(8,020		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	1,554			1,912			238			(1,239		)
Realized	Purchased electricity	(2,836		)	(3,923		)	(5,225		)	(10,078		)
Total gain (loss) recognized in income on derivatives		$	(342	)	$	(10,579	)	$	(9,411	)	$	(41,191	)

_______________

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

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2018, approximately 94.6% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated investment grade by rating agencies and 5.4% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of June 30, 2018, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE) platform, which requires the daily posting of margin calls as collateral through a futures and clearing agent. As of June 30, 2018, PSE had cash posted as collateral of $3.7 million related to contracts executed on this platform. As additional contracts are executed on this exchange, the amount of collateral to be posted will increase, subject to PSE’s established limit. PSE also has a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange

21

and clearing house in Canada. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the six months ended June 30, 2018.

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

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

_______________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

²  Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

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

(5) Fair Value Measurements

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

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

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

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

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

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

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $49.1 million and $48.5 million at June 30, 2018 and December 31, 2017, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		At June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount1	2	5,505,640		6,483,719		5,105,329		6,520,515
Long-term debt (variable-rate)	2	139,551		139,551		102,600		102,600
Total liabilities		$	5,645,191	$	6,623,270	$	5,457,929	$	6,862,050

Puget Sound Energy		At June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount2	2	3,895,042		4,598,167		3,499,911		4,550,130
Total liabilities		$	3,895,042	$	4,598,167	$	3,749,911	$	4,789,065

_______________

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

²  The carrying value includes debt issuances costs of $24.2 million and $24.6 million for June 30, 2018 and December 31, 2017, 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:

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Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At June 30, 2018						At December 31, 2017
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,229	$	3,660	$	10,889	$	9,866	$	3,525	$	13,391
Natural gas derivative instruments	6,510		6,062		12,572		6,973		4,041		11,014
Total assets	$	13,739	$	9,722	$	23,461	$	16,839	$	7,566	$	24,405
Liabilities:
Electric derivative instruments	$	36,991	$	1,651	$	38,642	$	46,623	$	2,427	$	49,050
Natural gas derivative instruments	24,144		2,113		26,257		34,926		2,118		37,044
Total liabilities	$	61,135	$	3,764	$	64,899	$	81,549	$	4,545	$	86,094

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

Puget Energy and Puget Sound Energy	Three Months Ended June 30,
(Dollars in Thousands)	2018									2017
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,186		$	5,096		$	6,282		$	3,788		$	1,752		$	5,540
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	366			—			366			339			—			339
Included in regulatory assets / liabilities	—			354			354			—			1,124			1,124
Settlements	(151		)	(1,800		)	(1,951		)	(2,508		)	(1,974		)	(4,482		)
Transferred into Level 3	—			—			—			—			—			—
Transferred out of Level 3	608			299			907			(976		)	554			(422		)
Balance at end of period	$	2,009		$	3,949		$	5,958		$	643		$	1,456		$	2,099

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

______________

¹  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.7 million and $0.5 million for the three months ended June 30, 2018 and 2017, respectively.

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

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

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2018:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,660	$	1,651	Discounted cash flow	Power prices (per MWh)	$	20.97	$	40.25	$	26.52
Natural gas	$	6,062	$	2,113	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.74	$	2.73	$	2.14

_______________

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

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The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,525	$	2,427	Discounted cash flow	Power prices (per MWh)	$	7.02	$	28.94	$	18.61
Natural gas	$	4,041	$	2,118	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.22	$	2.80	$	1.54

_______________

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

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At June 30, 2018 and December 31, 2017, a hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.1 million and $0.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

As of June 30, 2018, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. As of March 31, 2018, the Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017, causing an impairment of $1.9 million.

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

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

The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.

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

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

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(6) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion 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, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual pay credits of 4.0% each year in the defined benefit pension or 401k plan account. Those employees electing the defined benefits pension plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees.

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

In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has 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.

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

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

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

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2018			2017			2018		2017		2018			2017
Components of net periodic benefit cost:
Service cost	$	5,425		$	5,023		$	212	$	228	$	17		$	16
Interest cost	6,780			7,088			530		571		110			130
Expected return on plan assets	(12,569		)	(11,963		)	—		—		(117		)	(116		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,630			3,095			517		392		(142		)	(148		)
Net periodic benefit cost	$	2,873		$	2,850		$	1,270	$	1,202	$	(132	)	$	(118	)

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

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

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Change in benefit obligation:
Benefit obligation at beginning of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194
Service cost	10,851			20,081			423			913			35			72
Interest cost	13,560			28,373			1,060			2,285			220			500
Actuarial loss (gain)	—			40,945			—			2,722			—			725
Benefits paid	(21,300		)	(40,594		)	(1,080		)	(1,900		)	(562		)	(1,137		)
Medicare part D subsidy received	—			—			—			—			85			100
Administrative Expense	—			(931		)	—			—			—			—
Benefit obligation at end of period	$	703,592		$	700,481		$	56,157		$	55,754		$	11,232		$	11,454

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2018 are expected to be at least $18.0 million, $5.5 million and $0.3 million, respectively. During the three months ended June 30, 2018, the Company contributed $4.5 million and $0.6 million to fund the qualified pension plan and SERP, respectively. During the six months ended June 30, 2018, the Company contributed $9.0 million and $1.1 million to fund the qualified pension plan and SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plans.

(7) Regulation and Rates

General Rate Case Filing

In January 2017, PSE filed its general rate case (GRC) with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017

29

and new rates became effective December 19, 2017. The settlement agreement provides for a weighted cost of capital of 7.6% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%, annually.

The GRC also re-purposed the benefit for PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. As the Company monetizes PTCs, which are PTCs used on the filed tax returns, the regulatory liability is transferred to a reserve for Colstrip Units 1 and 2 decommissioning and remediation costs.

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, 2017.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or expedited rate filing (ERF). Approved electric fixed production energy costs can only be changed in a GRC or power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate.

On June 30, 2018, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance.  Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all deferred revenue for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 or 2018 decoupling revenue other than to record the previously unrecognized decoupling deferrals of $20.8 million at December 31, 2016.

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Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the six months ended June 30, 2018, PSE incurred $8.9 million in storm-related electric transmission and distribution system restoration costs, of which no current year amount was deferred to a regulatory asset. This compares to $20.8 million incurred in storm-related electric transmission and distribution system restoration costs for the six months ended June 30, 2017, of which $12.1 million was deferred to a regulatory asset. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

Washington Commission Tax Deferral Filing

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

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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. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents.

Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $129.2 million and $127.6 million as of June 30, 2018 and December 31, 2017, respectively. However, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE will accelerate the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $1.5 million, and is currently implementing a comprehensive inspection and remediation program. However, litigation is still pending regarding damage and personal injury claims.

Other Commitments and Contingencies

There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

(9) Other

Long-Term Debt

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

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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, 2017. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG 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, and the Alberta Investment Management Corporation. 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 June 30, 2018 is set forth below in this "Overview" section as well as in other sections of Management's Discussion and Analysis.

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2018 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon sufficient outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). 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, the Company will need to seek rate relief through a rate case on a regular and frequent basis in the foreseeable future after the investment is made. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

Washington state law also requires PSE to pursue electric conservation that is cost-effective, reliable and feasible. PSE’s mandate to pursue electric conservation initiatives may have a negative impact on the electric business financial performance due to lost margins from lower sales volumes as variable power costs are not part of the decoupling mechanism. Although not specified by Washington state law, the Washington Commission also sets natural gas conservation achievement standards for PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled. 

General Rate Case Filing

In January 2017, PSE filed its general rate case (GRC) with the Washington Commission. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017 and new rates 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, 2017.

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Washington Commission Tax Deferral Filing

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

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

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

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or expedited rate filing (ERF). Approved electric fixed production energy costs can only be changed in a GRC or power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate cap which limits the amount of 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.

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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, 2018	(1.1)%	$(25.2)
May 1, 2017	2.0	41.9
May 1, 2016	1.0	20.8
Natural Gas:
May 1, 2018	1.7%	$15.9
May 1, 2017	2.4	22.4
May 1, 2016	2.8	25.4

_______________

¹  The increase in revenue is net of reductions from excess earnings of $10.0 million for electric and $4.9 million for natural gas effective May 1, 2018, $11.9 million for electric and $2.2 million for natural gas effective May 1, 2017, and $11.9 million for electric and $5.5 million for natural gas effective May 1, 2016.

As noted earlier, at the time of the filings below, the Company was also limited to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation has been triggered as follows for natural gas with no impacts to electric:

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

_______________

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

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

On September 30, 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs.  The deferral period requested was January 1, 2017 through December 31, 2017 when rates went into

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effect from PSE's 2017 GRC.  On November 10, 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017.

For the six months ended June 30, 2018, in its PCA mechanism, PSE over recovered its power costs by $15.3 million of which no amount was apportioned to customers.  This compares to an under recovery of power costs of $8.6 million for the six months ended June 30, 2017 of which no amounts were apportioned to customers. Power costs decreased in 2018 compared to 2017, although the effect of the lower power costs in the PCA mechanism was offset by a decrease in load used to calculate the baseline amount and a slightly lower baseline rate in 2018.

Electric Conservation Rider

The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for the difference between actual conservation expenditures and the forecasted conservation expenditures from the prior year as well as the difference between actual load and 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, 2018	(0.8)%	$(18.0)
May 1, 2017	0.7	16.5
May 1, 2016	(0.5)	(11.7)

Electric Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. The 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, 2018	(0.1)%	$(1.3)
May 1, 2017	(0.04)	(0.9)
May 1, 2016	0.3	5.7

Federal Incentive Tracker Tariff

The Federal Incentive Tracker Tariff passes through to customers the benefits associated with the wind-related treasury grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for the difference between actual load and 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%.

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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)
May 1, 2018	0.4%	$(40.1)
January 1, 2018	0.2	(48.2)
January 1, 2017	0.3	(51.7)
January 1, 2016	(0.2)	(57.3)

Residential Exchange Benefit

The residential exchange program passes through the residential exchange program benefits that PSE receives from the Bonneville Power Administration (BPA).  Rates change bi-annually on October 1.

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
October 1, 2017	(0.6)%	$(80.8)

Natural Gas Rates

Natural Gas Conservation Rider

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2017	(0.1)	(1.0)
May 1, 2016	0.3	2.9

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. 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.

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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, 2018	(0.2)%	$(2.2)
May 1, 2017	(0.1)	(1.1)
May 1, 2016	0.4	3.5

Natural Gas Cost Recovery Mechanism

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

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

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

Purchased Gas Adjustment

PSE has a purchased gas adjustment (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 change annually on November 1.

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2017	(3.3)%	$(30.8)
November 1, 2016	(0.4)	(4.1)

Other Proceedings

Large Customer Retail Wheeling

On October 7, 2016, PSE filed a tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to the case reached an all-party settlement that converted the tariff to a special contract only allowing retail access for the loads of the Microsoft Corporation currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to Microsoft must be carbon free, (iii) there will be no reduction in Microsoft's funding of PSE’s conservation programs, (iv) Microsoft will pay a transition fee that will be a straight pass-through to customers and (v) Microsoft will fund enhanced low-income support. A definitive agreement among the parties, the special contract and supportive testimony

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were filed with the Washington Commission on April 11, 2017 with hearings that occurred on May 3, 2017. The Washington Commission issued an order on July 13, 2017 approving PSE’s special contract with Microsoft. Microsoft cannot begin taking service under the special contract until it has the required metering installed, has contracts for the supply and transmission of its power supply and pays the transition fee.

Voluntary Long-Term Renewable Energy

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

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

Other Factors and Trends

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. In October 2017, Puget Energy and PSE each entered into new 5-year credit facilities that replaced the previous facilities and are scheduled to mature in October 2022. Additional information on credit facilities is set forth below in the “Puget Sound Energy - Credit Facilities” and "Puget Energy - Credit Facility" sections.

Regulatory Compliance Costs and Expenditures

PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

Compliance with these or other future regulations, such as those pertaining to climate change, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.

Other Challenges and Strategies

Competition

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

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Results of Operations

Puget Sound Energy

Non-GAAP Financial Measures - Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), 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.

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Electric Margin

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory. The following chart displays the details of PSE's electric margin changes for the three months ended June 30, 2017 and 2018:

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

Three months ended June 30, 2017 compared to 2018

Electric Operating Revenue

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

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

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

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

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

Electric Power Costs

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

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

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

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

Six months ended June 30, 2017 compared to 2018

Electric Operating Revenue

Electric operating revenues increased $2.4 million primarily due to transportation and other revenues of $28.9 million and sales to other utilities of $3.7 million; partially offset by lower electric retail sales of $20.9 million and decoupling revenue of $10.8 million.  These items are discussed in detail below.

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• Electric retail sales decreased $20.9 million due to a decrease of $36.1 million from lower retail electricity usage of 3.0% compared to the prior year and partially offset by an increase in rates of $15.2 million due to the decoupling rate mechanism rate increase of 2.0% annually effective May 2017 and the GRC rate increase of 0.9% annually effective December 2017. The rate increases were partially offset by rate decrease in May 2018 of 3.5% due to change in corporate tax rates as a result of TCJA. The reduced usage was due to a decrease of residential and commercial use per customer of 4.8% and 1.1%, respectively, primarily due to a decrease in heating degree days of 12.0% compared to 2017.

• Sales to other utilities increased $3.7 million due to a 9.8% increase in volumes sold and a 13.9% increase in price. EIM sales drove the increase in volumes.

• Decoupling revenue decreased $10.8 million primarily due to a decrease in decoupling deferrals of $9.2 million as driven by actual revenue being closer to PSE's allowed revenue per the decoupling mechanism compared to 2017. This was primarily driven by a decrease in allowed revenue per customer compared to 2017 which was offset by lower customer usage. The remaining $1.6 million decrease is a result of fixed production costs collection being greater than allowed compared to 2017.

• Transportation and other revenue increased $28.9 million primarily due to a change in PTC deferral revenue of $51.2 million for the re-purpose of the PTCs; partially offset by tax reform deferrals for revenue subject to refunds of $24.1 million.

Electric Power Costs

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

• Purchased electricity expense decreased $26.1 million primarily due to a 7.3% decrease in wholesale electricity purchases and a 1.4% decrease in wholesale prices. The decrease in purchases was primarily driven by a decrease in load and an increase of wind and combustion turbine generation of 27.8% and 10.5%, respectively, which decreased the need to purchase additional wholesale power.

• Electric generation fuel expense decreased $13.3 million primarily due to a $10.1 million reduction in combustion turbine generation costs as a result of a reduction in peaker combustion turbine generation due to favorable wholesale electricity prices and wind and hydro production. There was also a $3.2 million reduction of coal generation costs primarily at Colstrip units 1 and 2 due to a shutdown during the second quarter of 2018 for maintenance.

Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE’s service territory. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates 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.

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

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

Three months ended June 30, 2017 compared to 2018

Natural Gas Operating Revenue

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

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

• Decoupling revenue decreased $2.3 million primarily due actual revenue being closer to PSE's allowed revenue per the decoupling mechanism compared to 2017. This was primarily driven by a decrease in allowed revenue per customer compared to 2017 which was offset by lower customer usage as discussed in the retails sales above.

• Other decoupling revenue increased $4.4 million primarily driven by ROR sharing accrual of $5.2 million in 2017 as compared to no ROR sharing accrual in 2018.

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• Transportation and other revenue decreased $2.9 million primarily due to tax reform deferrals for revenue subject to refund of $2.0 million.

Natural Gas Energy Costs

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

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

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

Six months ended June 30, 2017 compared to 2018

Natural Gas Operating Revenue

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

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

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

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

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

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

Natural Gas Energy Costs

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

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Other Operating Expenses and Other Income (Deductions)

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

Three months ended June 30, 2017 compared to 2018

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments expense decreased $10.7 million from a loss of $3.8 million. The primary driver for the decrease in losses consists of a $9.5 million gain due to an increase in natural gas forward prices of 8.3%.

• Utility operations and maintenance expense decreased $5.4 million primarily driven by a decrease in the following: (i) decrease of $2.7 million in wind generation contract maintenance due to replacement of capital units of property and (ii) decrease of $1.3 million due to lower meter service contracts tied to the Consumer Price Index in 2018 compared to 2017.

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

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

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Other Income, Interest Expense and Income Tax Expense    

• Interest expense decreased $3.7 million primarily related to lower interest rates on long-term debt due to the refinancing of the $250.0 million in junior subordinated notes and $200.0 million in senior secured notes at a lower interest.

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

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

Six months ended June 30, 2017 compared to 2018

Other Operating Expenses

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

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

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

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

Other Income, Interest Expense and Income Tax Expense    

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

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

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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 June 30, 2017 and 2018 are as follows:

Three months ended June 30, 2017 compared to 2018

Summary Results of Operation

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

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

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

Six months ended June 30, 2017 compared to 2018

Summary Results of Operation

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

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

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

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

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Capital Requirements

Contractual Obligations and Commercial Commitments

During the six months ended June 30, 2018, there were no material changes to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

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

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

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

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

Off-Balance Sheet Arrangements

As of June 30, 2018, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to support reliable energy delivery, meet regulatory requirements, and customer growth.  Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled $452.2 million for the six months ended June 30, 2018. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Thousands)	2018		2019		2020
Total energy delivery, technology and facilities expenditures	$	1,003,000	$	839,000	$	740,000

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

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Capital Resources

Cash from Operations

Puget Sound Energy	Six Months Ended June 30,
(Dollars in Millions)	2018			2017			Change
Net income	$	189,818		$	193,746		$	(3,928	)
Non-cash items1	351,940			408,783			(56,843		)
Changes in cash flow resulting from working capital2	153,022			175,755			(22,733		)
Regulatory assets and liabilities	4,591			(46,101		)	50,692
Other noncurrent assets and liabilities3	(14,956		)	(32,507		)	17,551
Net cash provided by operating activities	$	684,415		$	699,676		$	(15,261	)

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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.

Six Months Ended June 30, 2018 compared to 2017

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

• Cash flow adjustments resulting from non-cash items decreased $56.8 million primarily due to changes in deferred income tax and tax credits of $76.1 million, production tax credit monetization of $51.2 million and derivative instruments of $31.0 million offset by changes in depreciation and amortization of $101.9 million. For further discussion, see note 7, "Regulation and Rates" and Management's Discussion and Analysis, "Other Operating Expenses" in Item 2.

• Cash flow resulting from regulatory assets and liabilities increased $50.7 million primarily due to deferred accounting treatment for the impacts of tax reform and decoupling collections. For further discussion, see Management's Discussion and Analysis, "Electric Operating Revenue" and "Natural Gas Operating Revenue" in Item 2.

Puget Energy	Six Months Ended June 30,
(Dollars in Millions)	2018			2017			Change
Net income	$	(39,276	)	$	(30,921	)	$	(8,355	)
Non-cash items1	(2,725		)	(13,458		)	10,733
Changes in cash flow resulting from working capital2	3,438			(8,415		)	11,853
Regulatory assets and liabilities	—			—			—
Other noncurrent assets and liabilities3	(6,655		)	18,788			(25,443		)
Net cash provided by operating activities	$	(45,218	)	$	(34,006	)	$	(11,212	)

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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.

Six Months Ended June 30, 2018 compared to 2017

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

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

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

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

Financing Program

The Company's 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 and operations to fund its needs over the next twelve months.

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

Puget Sound Energy

Credit Facilities

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

The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of June 30, 2018, 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 London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

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

Demand Promissory Note

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

Long Term Debt

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

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

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

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

Debt Restrictive Covenants

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

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

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

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

At June 30, 2018, PSE had approximately $7.1 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations

On November 21, 2016, PSE filed a shelf registration statement under which it may issue, as of the date of this report, up to $200.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The shelf registration will expire in November 2019.

Dividend Payment Restrictions

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

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

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.

56

Puget Energy

Credit Facility

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

The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of June 30, 2018, there was $139.6 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of June 30, 2018, Puget Energy was in compliance with all applicable covenants.

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.7 to 1.0 for the twelve months ended June 30, 2018.

At June 30, 2018, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Other

New Accounting Pronouncements

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

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents.

Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $129.2 million and $127.6 million as of June 30, 2018 and December 31, 2017, respectively. However, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE will accelerate the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $1.5 million, and is currently implementing a comprehensive inspection and remediation program. However, litigation is still pending regarding damage and personal injury claims.

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Regional Haze Rule

On January 10, 2017, the EPA provided revisions to the Regional Haze Rule which were published in the Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however, the end date will remain 2028. Aspects of these revisions are currently being challenged by various entities nationwide and 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 on October 23, 2015. On March 31, 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10, 2017, the EPA proposed to repeal the CPP rule. The EPA is now reportedly developing a replacement CPP rule for Section 111(d) and it is expected sometime in the third quarter of 2018. PSE is still monitoring these developments and cannot yet predict a final outcome.

Washington Clean Air Rule

The CAR was adopted on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. On September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. On December 15, 2017, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in March 2018. The federal court litigation currently is stayed pending resolution of the state case.

Related Party Transactions

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

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

58

Item 3.     Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Commodity Price Risk

The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee (EMC) establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.    

PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  

Counterparty Credit Risk

PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. PSE manages credit risk with policies and procedures for counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB)) with its counterparties to mitigate credit exposure.

Interest Rate Risk

The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable-rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also enter into swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.

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Item 4.     Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2018, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

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

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

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2018, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

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

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

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

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PART II                  OTHER INFORMATION

Item 1.     Legal Proceedings

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

Item 1A.     Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A, "Risk Factors" of the Company's Annual Report on Form 10-K for the period ended December 31, 2017.

Item 6.     Exhibits

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

61

EXHIBIT INDEX

3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
4.1	Fifth Supplemental Indenture from Puget Sound Energy, Inc. to U.S Bank National Association, dated May 23, 2018 (incorporated by reference to Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K Commission File No. 1-4393).
4.2	Purchase Agreement, dated June 4, 2018, between Puget Sound Energy, Inc. and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Securities USA LLC and each of the other underwriters named in Schedule A thereto (incorporated by reference to Exhibit 1.1 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2013 through 2017 and 6 months ended June 30, 2018).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2013 through 2017 and the 6 months ended June 30, 2018).
31.1*	Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*	Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*	Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended June 30, 2018 filed on August 1, 2018 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.

62

SIGNATURES

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

		PUGET ENERGY, INC. PUGET SOUND ENERGY, INC.
		/s/ Stephen King
		Stephen King Controller & Principal Accounting Officer
Date:	August 1, 2018

63

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
	June 30,			December 31,
	2018			2017			2016			2015			2014
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	357,661		$	430,337		$	453,103		$	332,954		$	228,820
AFUDC - equity	(15,407		)	(15,027		)	(12,576		)	(9,325		)	(7,002		)
AFUDC - debt	(12,297		)	(10,826		)	(9,304		)	(7,575		)	(5,611		)
Total	$	329,957		$	404,484		$	431,223		$	316,054		$	216,207
Fixed charges:
Interest expense (a)	$	352,221		$	354,802		$	355,139		$	356,696		$	367,308
Other interest	15,407			15,027			12,576			9,325			7,002
Portion of rentals representative of the interest factor (b)	7,648			8,062			8,061			8,980			10,732
Total	$	375,276		$	377,891		$	375,776		$	375,001		$	385,042
Earnings available for combined fixed charges	$	705,233		$	782,375		$	806,999		$	691,055		$	601,249
Ratio of Earnings to Fixed Charges	1.88x			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
	June 30,			December 31,
	2018			2017			2016			2015			2014
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	462,217		$	532,040		$	555,928		$	430,089		$	325,955
AFUDC - equity	(15,407		)	(15,027		)	(12,576		)	(9,325		)	(7,002		)
AFUDC - debt	(12,297		)	(10,826		)	(9,304		)	(7,575		)	(5,611		)
Total	$	434,513		$	506,187		$	534,048		$	413,189		$	313,342
Fixed charges:
Interest expense (a)	$	236,266		$	240,144		$	242,983		$	247,571		$	264,926
Other interest	15,407			15,027			12,576			9,325			7,002
Portion of rentals representative of the interest factor (b)	7,648			8,062			8,061			8,980			10,732
Total	$	259,321		$	263,233		$	263,620		$	265,876		$	282,660
Earnings available for combined fixed charges	$	693,834		$	769,420		$	797,668		$	679,065		$	596,002
Ratio of Earnings to Fixed Charges	2.68x			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.

August 1, 2018

/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.

August 1, 2018

/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.

August 1, 2018

/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.

August 1, 2018

/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 endedJune 30, 2018 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.

August 1, 2018

/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 endedJune 30, 2018 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.

August 1, 2018

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

XML

Document And Entity Information	3 Months Ended
	Jun. 30, 2018 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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating revenue:
Electric	$ 501,510	$ 529,807	$ 1,201,196	$ 1,198,792
Natural gas	160,196	180,105	490,480	580,169
Other	10,146	9,855	18,184	18,038
Total operating revenue	671,852	719,767	1,709,860	1,796,999
Energy costs:
Purchased electricity	129,114	129,799	283,320	309,381
Electric generation fuel	29,750	34,163	72,173	85,473
Residential exchange	(16,091)	(15,121)	(40,035)	(38,568)
Purchased natural gas	53,872	63,183	181,487	215,984
Unrealized (gain) loss on derivative instruments, net	(6,911)	3,834	(7,907)	23,121
Utility operations and maintenance	140,131	145,555	300,655	297,618
Non-utility expense and other	8,419	6,144	21,249	11,339
Depreciation and amortization	152,105	119,457	336,617	234,710
Conservation amortization	24,025	25,691	60,888	60,453
Taxes other than income taxes	73,347	77,032	184,535	195,731
Total operating expenses	587,761	589,737	1,392,982	1,395,242
Operating income (loss)	84,091	130,030	316,878	401,757
Other income (expense):
Other income	8,116	6,263	21,573	12,223
Other expense	(2,330)	(2,042)	(4,428)	(3,257)
Non-hedged interest rate swap (expense) income	0	0	0	28
Interest charges:
AFUDC	3,318	2,555	6,201	4,730
Interest expense	(86,084)	(88,409)	(174,410)	(176,991)
Income (loss) before income taxes	7,111	48,397	165,814	238,490
Income tax (benefit) expense	3,469	13,122	15,272	75,665
Net income (loss)	3,642	35,275	150,542	162,825
Subsidiaries [Member]
Operating revenue:
Electric	501,510	529,807	1,201,196	1,198,792
Natural gas	160,196	180,105	490,480	580,169
Other	10,146	9,855	18,184	18,038
Total operating revenue	671,852	719,767	1,709,860	1,796,999
Energy costs:
Purchased electricity	129,114	129,799	283,320	309,381
Electric generation fuel	29,750	34,163	72,173	85,473
Residential exchange	(16,091)	(15,121)	(40,035)	(38,568)
Purchased natural gas	53,872	63,183	181,487	215,984
Unrealized (gain) loss on derivative instruments, net	(6,911)	3,834	(7,907)	23,121
Utility operations and maintenance	140,131	145,555	300,655	297,618
Non-utility expense and other	10,834	9,374	20,614	17,865
Depreciation and amortization	152,080	119,457	336,570	234,710
Conservation amortization	24,025	25,691	60,888	60,453
Taxes other than income taxes	73,347	77,032	184,535	195,731
Total operating expenses	590,151	592,967	1,392,300	1,401,768
Operating income (loss)	81,701	126,800	317,560	395,231
Other income (expense):
Other income	8,113	6,126	15,756	12,086
Other expense	(2,330)	(2,042)	(4,428)	(3,257)
Interest charges:
AFUDC	3,318	2,555	6,201	4,730
Interest expense	(57,020)	(59,991)	(116,575)	(120,453)
Income (loss) before income taxes	33,782	73,448	218,514	288,337
Income tax (benefit) expense	7,004	22,794	28,696	94,591
Net income (loss)	$ 26,778	$ 50,654	$ 189,818	$ 193,746

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Parent [Line Items]
Net income (loss)	$ 3,642	$ 35,275	$ 150,542	$ 162,825
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	227	(214)	453	666
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	0	(5,230)	0
Other comprehensive income (loss)	227	(214)	(4,777)	666
Comprehensive income (loss)	3,869	35,061	145,765	163,491
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	26,778	50,654	189,818	193,746
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,863	2,123	5,727	5,339
Amortization of treasury interest rate swaps to earnings, net of tax	96	79	192	158
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	0	(27,333)	0
Other comprehensive income (loss)	2,959	2,202	(21,414)	5,497
Comprehensive income (loss)	$ 29,737	$ 52,856	$ 168,404	$ 199,243

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 20	$ (115)	$ 80	$ 359
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	761	1,143	1,522	2,875
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 43	$ 51	$ 86

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively):
Electric plant	$ 8,305,168	$ 8,135,847
Natural gas plant	3,444,954	3,307,545
Common plant	905,018	811,815
Less: Accumulated depreciation and amortization	(2,623,659)	(2,428,524)
Net utility plant	10,031,481	9,826,683
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	222,170	182,355
Total other property and investments	1,878,683	1,838,868
Current assets:
Cash and cash equivalents	8,117	26,616
Restricted cash	10,083	10,145
Accounts receivable, net of allowance for doubtful accounts	218,306	341,110
Unbilled revenue	123,214	222,186
Materials and supplies, at average cost	112,913	107,003
Fuel and gas inventory, at average cost	51,084	49,908
Unrealized gain on derivative instruments	19,872	22,247
Prepaid expense and other	23,418	21,996
Power contract acquisition adjustment gain	8,480	12,207
Total current assets	575,487	813,418
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651	4,576
Regulatory assets related to power contracts	17,754	19,454
Other regulatory assets	818,081	948,532
Derivative Asset, Noncurrent	3,589	2,158
Power contract acquisition adjustment gain	159,168	162,711
Other	84,159	74,389
Total other long-term and regulatory assets	1,087,402	1,211,820
Total assets	13,573,053	13,690,789
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	565,600	465,355
Accumulated other comprehensive income (loss), net of tax	(29,059)	(24,282)
Total common shareholder's equity	3,845,498	3,750,030
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,164,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	0	250,000
Long-term debt	1,939,551	1,902,600
Debt discount, issuance costs and other	(220,632)	(220,943)
Total long-term debt	5,645,191	5,257,929
Total capitalization	9,490,689	9,007,959
Current liabilities:
Accounts payable	308,305	359,586
Short-term debt	28,000	329,463
Current maturities of long-term debt	0	200,000
Purchased gas adjustment liability	38,645	16,051
Accrued expenses:
Taxes	104,092	117,948
Salaries and wages	42,180	53,220
Interest	69,564	73,564
Unrealized loss on derivative instruments	49,776	64,859
Power contract acquisition adjustment loss	2,585	2,762
Other	93,900	80,206
Total current liabilities	737,047	1,297,659
Long-term and regulatory liabilities:
Deferred income taxes	774,195	746,868
Unrealized loss on derivative instruments	15,123	21,235
Regulatory liabilities	743,766	731,587
Regulatory liability for deferred income taxes	994,987	1,011,626
Regulatory liabilities related to power contracts	167,647	174,918
Power contract acquisition adjustment loss	15,169	16,693
Other deferred credits	634,430	682,244
Total long-term and regulatory liabilities	3,345,317	3,385,171
Commitments and contingencies (Note 8)
Total capitalization and liabilities	13,573,053	13,690,789
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress of $575,180 and $495,937, respectively):
Electric plant	10,389,267	10,232,771
Natural gas plant	4,018,260	3,882,733
Common plant	935,706	843,145
Less: Accumulated depreciation and amortization	(5,311,752)	(5,131,966)
Net utility plant	10,031,481	9,826,683
Other property and investments:
Other property and investments	77,109	76,350
Total other property and investments	77,109	76,350
Current assets:
Cash and cash equivalents	7,104	25,864
Restricted cash	10,083	10,145
Accounts receivable, net of allowance for doubtful accounts	224,901	343,546
Unbilled revenue	123,214	222,186
Materials and supplies, at average cost	112,913	107,003
Fuel and gas inventory, at average cost	49,761	48,585
Unrealized gain on derivative instruments	19,872	22,247
Prepaid expense and other	23,418	21,996
Total current assets	571,266	801,572
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,651	4,576
Other regulatory assets	818,081	948,540
Derivative Asset, Noncurrent	3,589	2,158
Other	81,862	71,827
Total other long-term and regulatory assets	908,183	1,027,101
Total assets	11,588,039	11,731,706
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Earnings reinvested in the business	566,758	452,066
Accumulated other comprehensive income (loss), net of tax	(148,320)	(126,906)
Total common shareholder's equity	3,694,402	3,601,124
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,164,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	0	250,000
Debt discount, issuance costs and other	(31,230)	(26,361)
Total long-term debt	3,895,042	3,549,911
Total capitalization	7,589,444	7,151,035
Current liabilities:
Accounts payable	308,304	359,585
Short-term debt	28,000	329,463
Current maturities of long-term debt	0	200,000
Purchased gas adjustment liability	38,645	16,051
Accrued expenses:
Taxes	104,092	117,063
Salaries and wages	42,180	53,220
Interest	43,672	47,837
Unrealized loss on derivative instruments	49,776	64,859
Other	93,900	80,206
Total current liabilities	708,569	1,268,284
Long-term and regulatory liabilities:
Deferred income taxes	906,226	869,473
Unrealized loss on derivative instruments	15,123	21,235
Regulatory liabilities	742,443	730,273
Regulatory liability for deferred income taxes	995,599	1,012,260
Other deferred credits	630,635	679,146
Total long-term and regulatory liabilities	3,290,026	3,312,387
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$ 11,588,039	$ 11,731,706

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
ASSETS
Construction work in progress	$ 637,322	$ 495,937
Current assets:
Allowance for doubtful accounts	$ 10,716	$ 8,901
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 (in shares)	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 637,322	$ 495,937
Current assets:
Allowance for doubtful accounts	$ 10,716	$ 8,901
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 (in shares)	85,903,791	85,903,791

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating activities:
Net income (loss)	$ 150,542	$ 162,825
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	336,617	234,710
Conservation amortization	60,888	60,453
Deferred income taxes and tax credits, net	10,567	75,665
Net unrealized (gain) loss on derivative instruments	(7,907)	22,980
AFUDC – equity	(7,146)	(6,766)
Monetized production tax credits	(51,181)	0
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities	7,377	8,283
Funding of pension liability	(9,000)	(18,000)
Regulatory Assets	4,591	(46,101)
Other long-term assets and liabilities	(12,611)	4,281
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	220,207	196,179
Materials and supplies	(5,910)	5,606
Fuel and gas inventory	(1,176)	2,473
Prepayments and other	(1,422)	13,900
Purchased gas adjustment	22,594	13,765
Accounts payable	(47,040)	(49,478)
Taxes payable	(13,856)	(9,296)
Other	(16,937)	(5,809)
Net cash provided by (used in) operating activities	639,197	665,670
Investing activities:
Construction expenditures - excluding equity AFUDC	(490,623)	(496,652)
Other	1,956	(6,642)
Net cash provided by (used in) investing activities	(488,667)	(503,294)
Financing activities:
Change in short-term debt, net	(301,463)	(240,763)
Dividends paid	(55,525)	(132)
Proceeds from long-term debt and bonds issued	631,701	48,073
Redemption of bonds and notes	(450,000)	0
Other	6,196	9,003
Net cash provided by (used in) financing activities	(169,091)	(183,819)
Net increase (decrease) in cash and cash equivalents	(18,561)	(21,443)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning of Period	36,761	41,296
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, End of Period	18,200	19,853
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	164,823	163,228
Cash payments (refunds) for income taxes	5,169	0
Accounts payable for capital expenditures eliminated from cash flows	97,614	54,419
Subsidiaries [Member]
Operating activities:
Net income (loss)	189,818	193,746
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	336,570	234,710
Conservation amortization	60,888	60,453
Deferred income taxes and tax credits, net	18,519	94,590
Net unrealized (gain) loss on derivative instruments	(7,907)	23,121
AFUDC – equity	(7,146)	(6,766)
Monetized production tax credits	(51,181)	0
Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities	2,197	2,675
Funding of pension liability	(9,000)	(18,000)
Regulatory Assets	4,591	(46,101)
Other long-term assets and liabilities	(5,956)	(14,507)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	216,047	205,327
Materials and supplies	(5,910)	5,606
Fuel and gas inventory	(1,176)	2,473
Prepayments and other	(1,422)	13,900
Purchased gas adjustment	22,594	13,765
Accounts payable	(47,040)	(49,478)
Taxes payable	(12,971)	(9,296)
Other	(17,100)	(6,542)
Net cash provided by (used in) operating activities	684,415	699,676
Investing activities:
Construction expenditures - excluding equity AFUDC	(452,220)	(431,536)
Other	1,956	(6,205)
Net cash provided by (used in) investing activities	(450,264)	(437,741)
Financing activities:
Change in short-term debt, net	(301,463)	(240,763)
Dividends paid	(102,456)	(51,574)
Proceeds from long-term debt and bonds issued	594,750	0
Redemption of bonds and notes	(450,000)	0
Other	6,196	9,003
Net cash provided by (used in) financing activities	(252,973)	(283,334)
Net increase (decrease) in cash and cash equivalents	(18,822)	(21,399)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning of Period	36,009	40,899
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, End of Period	17,187	19,500
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	112,354	112,801
Cash payments (refunds) for income taxes	9,631	0
Accounts payable for capital expenditures eliminated from cash flows	$ 97,614	$ 54,419

XML

Summary of Consolidation Policy

3 Months Ended

Jun. 30, 2018

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 LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of June 30, 2018, Puget LNG has incurred $145.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. 

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 determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, 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. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

For Puget Energy, $144.7 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $113.4 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

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New Accounting Pronouncements

3 Months Ended

Jun. 30, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Recently Adopted Accounting Guidance

Income Taxes

In March 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-05, "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118". The staff of the U.S. Securities and Exchange Commission (SEC) recognized the complexity of reflecting the impacts of the Tax Cuts Job Act (TCJA), and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (SAB 118), which clarifies accounting for income taxes under Accounting Standards Codification (ASC) 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysis and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (i) a company is complete with its accounting for certain effects of tax reform, (ii) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (iii) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and has made a reasonable estimate as to the other effects and has reflected the measurement and accounting of the effects in the consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. The Company has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to the Company's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018. At December 31, 2017, the Company did not identify any effects of the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate. Additionally, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for impacts of tax reform. For additional information, see Note 7, "Regulation and Rates" to the consolidated financial statements included in Item 1 of this report.

Stranded Tax Effects in AOCI

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

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

Retirement Benefits

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

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

Statement of Cash Flows

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

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

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

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

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

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

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)". Accounting Standards Update (ASU) 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.

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

Accounting Standards Issued but Not Yet Adopted

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification 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 leases guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company plans to elect this practical expedient, and will evaluate new and modified land easements as of the first quarter of fiscal year 2019.

This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets.

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Revenue

3 Months Ended

Jun. 30, 2018

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 June 30,			Six Months Ended June 30,
Revenue from contracts with customers:	2018			2018
Electric retail	$	468,378		$	1,099,184
Natural gas retail	158,544			492,578
Other	38,930			81,364
Total revenue from contracts with customers	665,852			1,673,126
Alternative revenue programs	(8,815		)	(23,897		)
Other non-customer revenue	14,815			60,631
Total operating revenue	$	671,852		$	1,709,860

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

Other Revenue from Contracts with Customers

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

Electric Transmission and Natural Gas Transportation

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 gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the Federal Energy Regulatory Commission (FERC) and, therefore, corresponds directly to the value to the customer for performance completed to date.

Biogas

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

Wholesale Revenue

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

Other Revenue

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

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Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Jun. 30, 2018

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 June 30, 2018					At December 31, 2017
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	10,889	$	38,642	*	$	13,391	$	49,050
Natural gas derivatives (MMBtus)3	299.2 million	12,572		26,257		332.1 million	11,014		37,044
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094
Current		$	19,872	$	49,776		$	22,247	$	64,859
Long-term		3,589		15,123			2,158		21,235
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094

_______________

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 172.5 million One Million British Thermal Units (MMBtu) and purchased electricity of 3.7 million Megawatt Hours (MWhs) at June 30, 2018, and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017.

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 June 30, 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	$	23,461	$	—	$	23,461	$	(17,120	)	$	—		$	6,341
Liabilities:
Energy derivative contracts	64,899		—		64,899		(17,120		)	(1,220		)	46,559

Puget Energy and Puget Sound Energy
	At December 31, 2017
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801

_______________

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

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

Puget Energy and Puget Sound Energy		Three Months Ended June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Classification	2018			2017			2018			2017
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	—		$	—		$	28
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	5,357			(5,746		)	7,669			(21,882		)
Realized	Electric generation fuel	(4,417		)	(2,822		)	(12,093		)	(8,020		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	1,554			1,912			238			(1,239		)
Realized	Purchased electricity	(2,836		)	(3,923		)	(5,225		)	(10,078		)
Total gain (loss) recognized in income on derivatives		$	(342	)	$	(10,579	)	$	(9,411	)	$	(41,191	)

_______________

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

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2018, approximately 94.6% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated investment grade by rating agencies and 5.4% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of June 30, 2018, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE) platform, which requires the daily posting of margin calls as collateral through a futures and clearing agent. As of June 30, 2018, PSE had cash posted as collateral of $3.7 million related to contracts executed on this platform. As additional contracts are executed on this exchange, the amount of collateral to be posted will increase, subject to PSE’s established limit. PSE also has a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange and clearing house in Canada. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the six months ended June 30, 2018.

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

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

_______________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

²  Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

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

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Fair Value Measurements

3 Months Ended

Jun. 30, 2018

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 $49.1 million and $48.5 million at June 30, 2018 and December 31, 2017, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows:

Puget Energy		At June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount1	2	5,505,640		6,483,719		5,105,329		6,520,515
Long-term debt (variable-rate)	2	139,551		139,551		102,600		102,600
Total liabilities		$	5,645,191	$	6,623,270	$	5,457,929	$	6,862,050

Puget Sound Energy		At June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount2	2	3,895,042		4,598,167		3,499,911		4,550,130
Total liabilities		$	3,895,042	$	4,598,167	$	3,749,911	$	4,789,065

_______________

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

²  The carrying value includes debt issuances costs of $24.2 million and $24.6 million for June 30, 2018 and December 31, 2017, 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 June 30, 2018						At December 31, 2017
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,229	$	3,660	$	10,889	$	9,866	$	3,525	$	13,391
Natural gas derivative instruments	6,510		6,062		12,572		6,973		4,041		11,014
Total assets	$	13,739	$	9,722	$	23,461	$	16,839	$	7,566	$	24,405
Liabilities:
Electric derivative instruments	$	36,991	$	1,651	$	38,642	$	46,623	$	2,427	$	49,050
Natural gas derivative instruments	24,144		2,113		26,257		34,926		2,118		37,044
Total liabilities	$	61,135	$	3,764	$	64,899	$	81,549	$	4,545	$	86,094

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

Puget Energy and Puget Sound Energy	Three Months Ended June 30,
(Dollars in Thousands)	2018									2017
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,186		$	5,096		$	6,282		$	3,788		$	1,752		$	5,540
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	366			—			366			339			—			339
Included in regulatory assets / liabilities	—			354			354			—			1,124			1,124
Settlements	(151		)	(1,800		)	(1,951		)	(2,508		)	(1,974		)	(4,482		)
Transferred into Level 3	—			—			—			—			—			—
Transferred out of Level 3	608			299			907			(976		)	554			(422		)
Balance at end of period	$	2,009		$	3,949		$	5,958		$	643		$	1,456		$	2,099

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

______________

¹  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.7 million and $0.5 million for the three months ended June 30, 2018 and 2017, respectively.

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

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

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2018:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,660	$	1,651	Discounted cash flow	Power prices (per MWh)	$	20.97	$	40.25	$	26.52
Natural gas	$	6,062	$	2,113	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.74	$	2.73	$	2.14

_______________

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,525	$	2,427	Discounted cash flow	Power prices (per MWh)	$	7.02	$	28.94	$	18.61
Natural gas	$	4,041	$	2,118	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.22	$	2.80	$	1.54

_______________

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

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At June 30, 2018 and December 31, 2017, a hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.1 million and $0.9 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis

Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.

ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

As of June 30, 2018, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. As of March 31, 2018, the Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017, causing an impairment of $1.9 million.

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

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

The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.

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

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

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Retirement Benefits

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

Retirement Benefits

Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion 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, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual pay credits of 4.0% each year in the defined benefit pension or 401k plan account. Those employees electing the defined benefits pension plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees.

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

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

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

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

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

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2018			2017			2018		2017		2018			2017
Components of net periodic benefit cost:
Service cost	$	5,425		$	5,023		$	212	$	228	$	17		$	16
Interest cost	6,780			7,088			530		571		110			130
Expected return on plan assets	(12,569		)	(11,963		)	—		—		(117		)	(116		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,630			3,095			517		392		(142		)	(148		)
Net periodic benefit cost	$	2,873		$	2,850		$	1,270	$	1,202	$	(132	)	$	(118	)

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

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

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Change in benefit obligation:
Benefit obligation at beginning of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194
Service cost	10,851			20,081			423			913			35			72
Interest cost	13,560			28,373			1,060			2,285			220			500
Actuarial loss (gain)	—			40,945			—			2,722			—			725
Benefits paid	(21,300		)	(40,594		)	(1,080		)	(1,900		)	(562		)	(1,137		)
Medicare part D subsidy received	—			—			—			—			85			100
Administrative Expense	—			(931		)	—			—			—			—
Benefit obligation at end of period	$	703,592		$	700,481		$	56,157		$	55,754		$	11,232		$	11,454

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2018 are expected to be at least $18.0 million, $5.5 million and $0.3 million, respectively. During the three months ended June 30, 2018, the Company contributed $4.5 million and $0.6 million to fund the qualified pension plan and SERP, respectively. During the six months ended June 30, 2018, the Company contributed $9.0 million and $1.1 million to fund the qualified pension plan and SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plans.

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Regulation and Rates

3 Months Ended

Jun. 30, 2018

Regulation and Rates [Abstract]

Regulation and Rates

Regulation and Rates

General Rate Case Filing

In January 2017, PSE filed its general rate case (GRC) with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017 and new rates became effective December 19, 2017. The settlement agreement provides for a weighted cost of capital of 7.6% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%, annually.

The GRC also re-purposed the benefit for PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. As the Company monetizes PTCs, which are PTCs used on the filed tax returns, the regulatory liability is transferred to a reserve for Colstrip Units 1 and 2 decommissioning and remediation costs.

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, 2017.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or expedited rate filing (ERF). Approved electric fixed production energy costs can only be changed in a GRC or power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate.

On June 30, 2018, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980.  If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance.  Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all deferred revenue for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 or 2018 decoupling revenue other than to record the previously unrecognized decoupling deferrals of $20.8 million at December 31, 2016.

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the six months ended June 30, 2018, PSE incurred $8.9 million in storm-related electric transmission and distribution system restoration costs, of which no current year amount was deferred to a regulatory asset. This compares to $20.8 million incurred in storm-related electric transmission and distribution system restoration costs for the six months ended June 30, 2017, of which $12.1 million was deferred to a regulatory asset. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

Washington Commission Tax Deferral Filing

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

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Commitments and Contingencies

3 Months Ended

Jun. 30, 2018

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. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents.

Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $129.2 million and $127.6 million as of June 30, 2018 and December 31, 2017, respectively. However, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE will accelerate the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027.

Greenwood

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $1.5 million, and is currently implementing a comprehensive inspection and remediation program. However, litigation is still pending regarding damage and personal injury claims.

Other Commitments and Contingencies

There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

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Other

6 Months Ended

Jun. 30, 2018

Other [Abstract]

Other

Other

Long-Term Debt

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

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Summary of Consolidation Policy (Policies)

3 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

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 LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of June 30, 2018, Puget LNG has incurred $145.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. 

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 determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring a Supplemental Environmental Impact Statement, 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. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG.

For Puget Energy, $144.7 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $113.4 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

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Revenue (Tables)

3 Months Ended

Jun. 30, 2018

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 June 30,			Six Months Ended June 30,
Revenue from contracts with customers:	2018			2018
Electric retail	$	468,378		$	1,099,184
Natural gas retail	158,544			492,578
Other	38,930			81,364
Total revenue from contracts with customers	665,852			1,673,126
Alternative revenue programs	(8,815		)	(23,897		)
Other non-customer revenue	14,815			60,631
Total operating revenue	$	671,852		$	1,709,860

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Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Jun. 30, 2018

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 June 30, 2018					At December 31, 2017
(Dollars in Thousands)	Volumes	Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Electric portfolio derivatives	*	$	10,889	$	38,642	*	$	13,391	$	49,050
Natural gas derivatives (MMBtus)3	299.2 million	12,572		26,257		332.1 million	11,014		37,044
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094
Current		$	19,872	$	49,776		$	22,247	$	64,859
Long-term		3,589		15,123			2,158		21,235
Total derivative contracts		$	23,461	$	64,899		$	24,405	$	86,094

_______________

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 172.5 million One Million British Thermal Units (MMBtu) and purchased electricity of 3.7 million Megawatt Hours (MWhs) at June 30, 2018, and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017.

Offsetting Assets and Liabilities

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 June 30, 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	$	23,461	$	—	$	23,461	$	(17,120	)	$	—		$	6,341
Liabilities:
Energy derivative contracts	64,899		—		64,899		(17,120		)	(1,220		)	46,559

Puget Energy and Puget Sound Energy
	At December 31, 2017
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted			Net Amount
Assets:
Energy derivative contracts	$	24,405	$	—	$	24,405	$	(17,940	)	$	—		$	6,465
Liabilities:
Energy derivative contracts	86,094		—		86,094		(17,940		)	(353		)	67,801

_______________

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

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 June 30, 2018						At December 31, 2017
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	1,356	$	—	$	1,356	$	3,187	$	—	$	3,187
Requested credit for adequate assurance	25,805		—		—		37,374		—		—
Forward value of contract3	1,220		3,691		—		353		2,639		—
Total	$	28,381	$	3,691	$	1,356	$	40,914	$	2,639	$	3,187

_______________

¹  Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.

²  Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

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

Parent Company [Member]

Derivative [Line Items]

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 June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Classification	2018			2017			2018			2017
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	—		$	—		$	28
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	5,357			(5,746		)	7,669			(21,882		)
Realized	Electric generation fuel	(4,417		)	(2,822		)	(12,093		)	(8,020		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	1,554			1,912			238			(1,239		)
Realized	Purchased electricity	(2,836		)	(3,923		)	(5,225		)	(10,078		)
Total gain (loss) recognized in income on derivatives		$	(342	)	$	(10,579	)	$	(9,411	)	$	(41,191	)

_______________

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

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Fair Value Measurements (Tables)

3 Months Ended

Jun. 30, 2018

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

Schedule of Impaired Intangible Assets

the Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 39.0% from December 31, 2017, causing an impairment of $1.9 million.

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

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

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 June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount1	2	5,505,640		6,483,719		5,105,329		6,520,515
Long-term debt (variable-rate)	2	139,551		139,551		102,600		102,600
Total liabilities		$	5,645,191	$	6,623,270	$	5,457,929	$	6,862,050

Puget Sound Energy		At June 30, 2018				At December 31, 2017
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	—	$	—	$	250,000	$	238,935
Long-term debt (fixed-rate), net of discount2	2	3,895,042		4,598,167		3,499,911		4,550,130
Total liabilities		$	3,895,042	$	4,598,167	$	3,749,911	$	4,789,065

_______________

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

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

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

Puget Energy and Puget Sound Energy	Three Months Ended June 30,
(Dollars in Thousands)	2018									2017
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	1,186		$	5,096		$	6,282		$	3,788		$	1,752		$	5,540
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	366			—			366			339			—			339
Included in regulatory assets / liabilities	—			354			354			—			1,124			1,124
Settlements	(151		)	(1,800		)	(1,951		)	(2,508		)	(1,974		)	(4,482		)
Transferred into Level 3	—			—			—			—			—			—
Transferred out of Level 3	608			299			907			(976		)	554			(422		)
Balance at end of period	$	2,009		$	3,949		$	5,958		$	643		$	1,456		$	2,099

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

______________

¹  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.7 million and $0.5 million for the three months ended June 30, 2018 and 2017, respectively.

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

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,660	$	1,651	Discounted cash flow	Power prices (per MWh)	$	20.97	$	40.25	$	26.52
Natural gas	$	6,062	$	2,113	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.74	$	2.73	$	2.14

_______________

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	3,525	$	2,427	Discounted cash flow	Power prices (per MWh)	$	7.02	$	28.94	$	18.61
Natural gas	$	4,041	$	2,118	Discounted cash flow	Natural gas prices (per MMBtu)	$	1.22	$	2.80	$	1.54

_______________

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

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

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

Parent Company [Member]

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

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:

Subsidiaries [Member]

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

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At June 30, 2018						At December 31, 2017
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,229	$	3,660	$	10,889	$	9,866	$	3,525	$	13,391
Natural gas derivative instruments	6,510		6,062		12,572		6,973		4,041		11,014
Total assets	$	13,739	$	9,722	$	23,461	$	16,839	$	7,566	$	24,405
Liabilities:
Electric derivative instruments	$	36,991	$	1,651	$	38,642	$	46,623	$	2,427	$	49,050
Natural gas derivative instruments	24,144		2,113		26,257		34,926		2,118		37,044
Total liabilities	$	61,135	$	3,764	$	64,899	$	81,549	$	4,545	$	86,094

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2018

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

Schedule of Changes in Projected Benefit Obligations

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

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Change in benefit obligation:
Benefit obligation at beginning of period	$	700,481		$	652,607		$	55,754		$	51,734		$	11,454		$	11,194
Service cost	10,851			20,081			423			913			35			72
Interest cost	13,560			28,373			1,060			2,285			220			500
Actuarial loss (gain)	—			40,945			—			2,722			—			725
Benefits paid	(21,300		)	(40,594		)	(1,080		)	(1,900		)	(562		)	(1,137		)
Medicare part D subsidy received	—			—			—			—			85			100
Administrative Expense	—			(931		)	—			—			—			—
Benefit obligation at end of period	$	703,592		$	700,481		$	56,157		$	55,754		$	11,232		$	11,454

Parent Company [Member]

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 and six months ended June 30, 2018 and 2017:

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

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

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 June 30,
(Dollars in Thousands)	2018			2017			2018		2017		2018			2017
Components of net periodic benefit cost:
Service cost	$	5,425		$	5,023		$	212	$	228	$	17		$	16
Interest cost	6,780			7,088			530		571		110			130
Expected return on plan assets	(12,569		)	(11,963		)	—		—		(117		)	(116		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,630			3,095			517		392		(142		)	(148		)
Net periodic benefit cost	$	2,873		$	2,850		$	1,270	$	1,202	$	(132	)	$	(118	)

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

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Summary of Consolidation Policy (Details) mi² in Thousands, $ in Millions	Jun. 30, 2018 USD ($) mi²
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Construction in Progress, Gross	$ 113.4
Puget LNG [Member]
Summary of Consolidation Policy
Construction in Progress and O&M Expenses	$ 145.5
Jointly Owned Non-Utility Plant Share	57.00%
Construction in Progress, Gross	$ 144.7

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New Accounting Pronouncements Stranded Taxes in AOCI (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
strandedtaxesinAOCI [Line Items]
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	$ 0	$ 5,230	$ 0	$ 5,230	$ 0
Subsidiaries [Member]
strandedtaxesinAOCI [Line Items]
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	$ 0	27,333	$ 0	$ 27,333	$ 0
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans		26,200
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Interest Rate Swaps		$ 1,100

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New Accounting Pronouncements Restricted Cash (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 8,117	$ 26,616	$ 7,805
Restricted cash	10,083	10,145	12,048
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	18,200		19,853
Subsidiaries [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	7,104	25,864	7,452
Restricted cash	10,083	$ 10,145	12,048
Total cash, cash equivalents and restricted cash shown in the statement of cash flows	$ 17,187		$ 19,500

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New Accounting Pronouncements Revenue Recognition (Details)	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Contracts with Customers from Rate-Regulated Sales of Electricity and Natural Gas Dur	93.30%	93.10%

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	$ 10,146	$ 9,855	$ 18,184	$ 18,038
Total operating revenue	671,852	719,767	1,709,860	1,796,999
606ElectricRetailRevenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	468,378		1,099,184
606NaturalGasRetailRevenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	158,544		492,578
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	38,930		81,364
Revenue from Contract with Customer [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	665,852		1,673,126
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	(8,815)		(23,897)
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	14,815		60,631
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	10,146	9,855	18,184	18,038
Total operating revenue	$ 671,852	$ 719,767	$ 1,709,860	$ 1,796,999

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions	3 Months Ended
	Jun. 30, 2018 MWh MMBTU	Dec. 31, 2017 MWh MMBTU
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	299.2	332.1
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	172.5	166.8
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh	3.7	2.9
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	Jun. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Unrealized gain on derivative instruments	$ 19,872	$ 22,247
Assets, Long-term	3,589	2,158
Derivative Liability, Current	49,776	64,859
Unrealized loss on derivative instruments	15,123	21,235
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	19,872	22,247
Assets, Long-term	3,589	2,158
Derivative Liability, Current	49,776	64,859
Unrealized loss on derivative instruments	15,123	21,235
Commodity Contract [Member]
Derivative [Line Items]
Assets	23,461	24,405
Derivative Liability	$ 64,899	$ 86,094

XML

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) $ in Thousands, MMBTU in Millions	Jun. 30, 2018 USD ($) MMBTU		Dec. 31, 2017 USD ($) MMBTU
Liabilities:
Derivative Asset, Current	$ 19,872		$ 22,247
Derivative Liability, Current	49,776		64,859
Derivative Asset, Noncurrent	3,589		2,158
Derivative Liability, Noncurrent	15,123		21,235
Commodity Contract [Member]
Assets:
Gross Amount Recognized in the Statement of Financial Position	23,461	[1]	24,405
Gross Amounts Offset in the Statement of Financial Position	0		0
Net of Amounts Presented in the Statement of Financial Position	23,461		24,405
Commodity Contracts	(17,120)		(17,940)
Cash Collateral Received	0		0
Net Amount	6,341		6,465
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	64,899	[1]	86,094
Gross Amounts Offset in the Statement of Financial Position	0		0
Net of Amounts Presented in the Statement of Financial Position	64,899		86,094
Commodity Contracts	(17,120)		(17,940)
Cash Collateral Posted	(1,220)		(353)
Net Amount	46,559		67,801
Subsidiaries [Member]
Liabilities:
Derivative Asset, Current	19,872		22,247
Derivative Liability, Current	49,776		64,859
Derivative Asset, Noncurrent	3,589		2,158
Derivative Liability, Noncurrent	15,123		21,235
Not Designated as Hedging Instrument [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position	23,461		24,405
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	64,899		86,094
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position	10,889		13,391
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	$ 38,642		$ 49,050
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	299.2		332.1
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position	$ 12,572		$ 11,014
Liabilities:
Net of Amounts Presented in the Statement of Financial Position	26,257		37,044
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Liabilities:
Derivative Asset, Current	19,872		22,247
Derivative Liability, Current	49,776		64,859
Derivative Asset, Noncurrent	3,589		2,158
Derivative Liability, Noncurrent	$ 15,123		$ 21,235

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

XML

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (6,911)	$ 3,834	$ (7,907)	$ 23,121
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	342	10,579	9,411	41,191
Not Designated as Hedging Instrument [Member] | Other Income (Deductions) [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	0	0	(28)
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	(5,357)	5,746	(7,669)	21,882
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	4,417	2,822	12,093	8,020
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	2,836	3,923	5,225	10,078
Not Designated as Hedging Instrument [Member] | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (1,554)	$ (1,912)	$ (238)	$ 1,239

XML

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		94.60%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		5.40%
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 28,381	$ 40,914
Posted Collateral		3,691	2,639
Additional Collateral, Aggregate Fair Value		1,356	3,187
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	3,700
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	1,356	3,187
Posted Collateral	[2]	0	0
Additional Collateral, Aggregate Fair Value	[2]	1,356	3,187
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	[2]	1,000
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	25,805	37,374
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		0	0
Forward Value of Contract [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[3]	1,220	353
Posted Collateral	[3]	3,691	2,639
Additional Collateral, Aggregate Fair Value	[3]	$ 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.

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

XML

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Liabilities:
Total long-term debt		$ 5,645,191	$ 5,257,929
Subsidiaries [Member]
Liabilities:
Total long-term debt		3,895,042	3,549,911
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		3,895,042	3,749,911
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		0	250,000
Long-term debt (fixed-rate), net of discount	[1]	3,895,042	3,499,911
Debt issuance costs	[1]	24,200	24,600
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		4,598,167	4,789,065
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		0	238,935
Long-term debt (fixed-rate), net of discount	[1]	$ 4,598,167	$ 4,550,130

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

XML

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		$ 5,645,191		$ 5,645,191		$ 5,257,929
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		6,282	$ 5,540	3,021	$ 1,597
Included in earnings	[1]	366	339	1,985	1,045
Included in regulatory assets/liabilities		354	1,124	5,329	3,582
Settlements		(1,951)	(4,482)	(4,256)	(7,142)
Transferred into Level 3		0	0	(1,837)	1,638
Transferred out of Level 3		907	(422)	1,716	1,379
Balance at end of period		5,958	2,099	5,958	2,099
Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		700	500	1,700	700
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,186	3,788	1,098	972
Included in earnings	[1]	366	339	1,985	1,045
Included in regulatory assets/liabilities		0	0	0	0
Settlements		(151)	(2,508)	(654)	(3,838)
Transferred into Level 3		0	0	(1,837)	2,191
Transferred out of Level 3		608	(976)	1,417	273
Balance at end of period		2,009	643	2,009	643
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		5,096	1,752	1,923	625
Included in earnings	[1]	0	0	0	0
Included in regulatory assets/liabilities		354	1,124	5,329	3,582
Settlements		(1,800)	(1,974)	(3,602)	(3,304)
Transferred into Level 3		0	0	0	(553)
Transferred out of Level 3		299	554	299	1,106
Balance at end of period		3,949	$ 1,456	3,949	$ 1,456
Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		3,895,042		3,895,042		3,549,911
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		23,461		23,461		24,405
Derivative Liability		64,899		64,899		86,094
Fair Value, Measurements, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		10,889		10,889		13,391
Derivative Liability		38,642		38,642		49,050
Fair Value, Measurements, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		12,572		12,572		11,014
Derivative Liability		26,257		26,257		37,044
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		13,739		13,739		16,839
Derivative Liability		61,135		61,135		81,549
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		7,229		7,229		9,866
Derivative Liability		36,991		36,991		46,623
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		6,510		6,510		6,973
Derivative Liability		24,144		24,144		34,926
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		9,722		9,722		7,566
Derivative Liability		3,764		3,764		4,545
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		3,660		3,660		3,525	[2]
Derivative Liability		1,651		1,651		2,427	[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		6,062		6,062		4,041	[2]
Derivative Liability		2,113		2,113		2,118	[2]
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		49,100		49,100		48,500
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		5,645,191		5,645,191		5,457,929
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		0		0		250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	5,505,640		5,505,640		5,105,329
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	139,551		139,551		102,600
Unamortized Debt Issuance Expense	[3]	26,600		26,600		27,900
Income Approach Valuation Technique [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		3,895,042		3,895,042		3,749,911
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		0		0		250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	3,895,042		3,895,042		3,499,911
Unamortized Debt Issuance Expense	[3]	24,200		24,200		24,600
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		6,623,270		6,623,270		6,862,050
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		0		0		238,935
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	6,483,719		6,483,719		6,520,515
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	139,551		139,551		102,600
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities		4,598,167		4,598,167		4,789,065
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		0		0		238,935
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	$ 4,598,167		$ 4,598,167		$ 4,550,130

[1] 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.7 million and $0.5 million for the three months ended June 30, 2018 and 2017, respectively. 2 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.7 million and $0.7 million for the six months ended June 30, 2018 and 2017, respectively.

[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 $26.6 million and $27.9 million for June 30, 2018 and December 31, 2017, respectively, which are not included in fair value.

XML

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended		12 Months Ended
	Jun. 30, 2018 USD ($) $ / MMBTU $ / MWh	Mar. 31, 2018 USD ($) $ / MWh	Dec. 31, 2017 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	$ 1,100,000		$ 900,000
Fair Value Inputs, Comparability Adjustments		39.00%
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	23,461,000		24,405,000
Derivative Liability	$ 64,899,000		$ 86,094,000
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	20.97		7.02
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	40.25		28.94
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	26.52		18.61
Electric Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 10,889,000		$ 13,391,000
Derivative Liability	$ 38,642,000		$ 49,050,000
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	1.74		1.22
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	2.73		2.80
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	2.14		1.54
Natural Gas Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 12,572,000		$ 11,014,000
Derivative Liability	26,257,000		37,044,000
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	23,461,000		24,405,000
Derivative Liability	$ 64,899,000		$ 86,094,000
Wells Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)		$ 1,907,000
Finite-Lived Intangible Assets, Net		4,302,000
Wells Project [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 2,395,000
Wells Project [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		9.69
Fair Value Inputs, Power Contract Costs		$ 4,126
Wells Project [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		25.30
Fair Value Inputs, Power Contract Costs		$ 4,126
Wells Project [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		17.50
Fair Value Inputs, Power Contract Costs		$ 4,126

XML

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost			$ 10,851		$ 20,081
Interest cost			13,560		28,373
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost			423		913
Interest cost			1,060		2,285
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost			35		72
Interest cost			220		$ 500
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 5,425	$ 5,023	10,851	$ 10,040
Interest cost	6,780	7,088	13,560	14,186
Expected return on plan assets	(12,559)	(11,942)	(25,119)	(23,892)
Amortization of prior service cost	(495)	(495)	(990)	(990)
Amortization of net loss (gain)	462	0	925	0
Net periodic benefit cost	(387)	(326)	(773)	(656)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	212	228	423	457
Interest cost	530	571	1,060	1,143
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	394	269	790	538
Net periodic benefit cost	1,147	1,079	2,295	2,160
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	17	16	35	36
Interest cost	110	130	220	250
Expected return on plan assets	(117)	(116)	(235)	(231)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(86)	(88)	(172)	(201)
Net periodic benefit cost	(76)	(58)	(152)	(146)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,425	5,023	10,851	10,040
Interest cost	6,780	7,088	13,560	14,186
Expected return on plan assets	(12,569)	(11,963)	(25,138)	(23,931)
Amortization of prior service cost	(393)	(393)	(787)	(787)
Amortization of net loss (gain)	3,630	3,095	7,260	6,524
Net periodic benefit cost	2,873	2,850	5,746	6,032
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	212	228	423	457
Interest cost	530	571	1,060	1,143
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	517	392	1,035	783
Net periodic benefit cost	1,270	1,202	2,540	2,405
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	17	16	35	36
Interest cost	110	130	220	250
Expected return on plan assets	(117)	(116)	(235)	(231)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(142)	(148)	(283)	(320)
Net periodic benefit cost	$ (132)	$ (118)	$ (263)	$ (265)

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Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 700,481	$ 652,607
Service cost	10,851	20,081
Interest cost	13,560	28,373
Actuarial loss/(gain)	0	40,945
Benefits paid	(21,300)	(40,594)
Medicare part D subsidiary received	0	0
Administrative Expense	0	(931)
Benefit obligation at end of period	703,592	700,481
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	55,754	51,734
Service cost	423	913
Interest cost	1,060	2,285
Actuarial loss/(gain)	0	2,722
Benefits paid	(1,080)	(1,900)
Medicare part D subsidiary received	0	0
Administrative Expense	0	0
Benefit obligation at end of period	56,157	55,754
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	11,454	11,194
Service cost	35	72
Interest cost	220	500
Actuarial loss/(gain)	0	725
Benefits paid	(562)	(1,137)
Medicare part D subsidiary received	85	100
Administrative Expense	0	0
Benefit obligation at end of period	$ 11,232	$ 11,454

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Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	11 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 12, 2014	Dec. 31, 2018
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	$ 9.0
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	$ 0.6	$ 1.1
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				5.5
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions				$ 0.3

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Regulation and Rates (Details) $ in Thousands					3 Months Ended		4 Months Ended	6 Months Ended		12 Months Ended
	Dec. 29, 2017 USD ($)	Dec. 19, 2017 USD ($)	Jan. 13, 2017	Jan. 01, 2017	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Apr. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jan. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)
Regulatory Assets [Line Items]
Income tax (benefit) expense					$ 3,469	$ 13,122	$ 34,600	$ 15,272	$ 75,665
Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Deferred Storm Costs Threshold											$ 10,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs											500
Income tax (benefit) expense					7,004	22,794		28,696	$ 94,591
Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period					8,900	20,800
Storm Damage Costs Deferred During Period					0	$ 12,100
Public Utilities, Rate Case, Deferred Storm Costs Threshold											$ 8,000
Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Deferred Revenue, Revenue Recognized										$ 20,800
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				2.20%
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		5.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		3.00%
General Rate Case [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Number of new mechanisms			2
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		7.60%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities		6.55%
Public Utilities, Requested Equity Capital Structure, Percentage		48.50%
Public Utilities, Requested Return on Equity, Percentage		9.50%
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ (35,500)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		(3.80%)
General Rate Case [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 20,200
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		0.90%
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ (23,600)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage	(2.70%)
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ (72,900)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage	(3.40%)
Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets					$ 129,200			$ 129,200				$ 127,600

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Commitments and Contingencies (Details) $ in Millions	Mar. 28, 2017 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value	$ 1.5
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)		25.00%
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)		50.00%
Jointly Owned Utility Plant		2
Colstrip Regulatory Asset [Domain]
Loss Contingencies [Line Items]
Regulatory Assets		$ 129.2	$ 127.6

XML

Other (Details) - Subsidiaries [Member] $ in Thousands	Jun. 04, 2018 USD ($)
Senior Secured Note [Member] | 4.223% Series Due 2048 [Member] [Domain]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 600,000
Debt Instrument, Interest Rate, Stated Percentage	4.223%
Senior Secured Note [Member] | 6.740% Series Due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 200,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 348,000