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 September 30, 2017

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 Nine Months Ended September 30, 2017 and 2016	5
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2017 and 2016	6
	Consolidated Balance Sheets – September 30, 2017 and December 31, 2016	7
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2017 and 2016	8
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Nine Months Ended September 30, 2017 and 2016	9
	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2017 and 2016	10
	Consolidated Balance Sheets – September 30, 2017 and December 31, 2016	11
	Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2017 and 2016	13
	Notes
	Combined Notes to Consolidated Financial Statements	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	53
Item 4.	Controls and Procedures	53
Part II.	Other Information	54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 5.	Other Information	54
Item 6.	Exhibits	55
Exhibit Index		56
Signatures		57

2

DEFINITIONS

ARO	Asset Retirement and Environmental Obligations
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EIM	Energy Imbalance Market
ERF	Expedited Rate Filing
FASB	Financial Accounting Standards Board
GAAP	U.S. Generally Accepted Accounting Principles
GRC	General Rate Case
ISDA	International Swaps and Derivatives Association
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
MMBtu	One Million British Thermal Units
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NPNS	Normal Purchase Normal Sale
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
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
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 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;

● 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;

● 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.

4

PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Operating revenue:
Electric	$	537,543		$	495,321		$	1,736,335		$	1,622,664
Natural gas	111,516			114,458			691,685			601,309
Other	11,318			8,499			29,356			25,170
Total operating revenue	660,377			618,278			2,457,376			2,249,143
Operating expenses:
Energy costs:
Purchased electricity	115,881			94,849			425,263			356,296
Electric generation fuel	66,584			70,503			152,057			165,627
Residential exchange	(14,246		)	(15,577		)	(52,814		)	(49,093		)
Purchased natural gas	32,224			34,041			248,208			205,418
Unrealized (gain) loss on derivative instruments, net	(23		)	6,327			23,098			(57,218		)
Utility operations and maintenance	141,003			138,265			438,622			422,273
Non-utility expense and other	7,319			4,708			18,658			15,520
Depreciation and amortization	120,829			110,022			355,538			328,809
Conservation amortization	25,395			21,800			85,847			77,551
Taxes other than income taxes	66,367			65,268			262,099			235,431
Total operating expenses	561,333			530,206			1,956,576			1,700,614
Operating income (loss)	99,044			88,072			500,800			548,529
Other income (expense):
Other income	7,151			6,130			19,375			19,187
Other expense	(2,878		)	(5,025		)	(6,134		)	(8,488		)
Non-hedged interest rate swap (expense) income	—			563			28			(651		)
Interest charges:
AFUDC	3,123			2,702			7,853			7,663
Interest expense	(88,780		)	(89,297		)	(265,771		)	(266,786		)
Income (loss) before income taxes	17,660			3,145			256,151			299,454
Income tax (benefit) expense	4,824			810			80,489			91,380
Net income (loss)	$	12,836		$	2,335		$	175,662		$	208,074

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017		2016
Net income (loss)	$	12,836		$	2,335		$	175,662	$	208,074
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $(143), $(16), $216 and $(216), respectively	(266		)	(29		)	400		(400		)
Other comprehensive income (loss)	(266		)	(29		)	400		(400		)
Comprehensive income (loss)	$	12,570		$	2,306		$	176,062	$	207,674

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

6

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS
	September 30, 2017			December 31, 2016
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):
Electric plant	$	7,918,877		$	7,673,772
Natural gas plant	3,253,977			3,051,586
Common plant	738,409			594,994
Less: Accumulated depreciation and amortization	(2,409,508		)	(2,161,796		)
Net utility plant	9,501,755			9,158,556
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	166,996			106,418
Total other property and investments	1,823,509			1,762,931
Current assets:
Cash and cash equivalents	6,768			28,878
Restricted cash	9,302			12,418
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively	232,699			329,375
Unbilled revenue	126,252			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	108,814			106,378
Fuel and natural gas inventory, at average cost	60,645			58,181
Unrealized gain on derivative instruments	16,605			54,341
Prepaid expense and other	35,655			43,046
Power contract acquisition adjustment gain	15,932			33,413
Total current assets	612,672			902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,566			72,038
Power cost adjustment mechanism	4,540			4,531
Regulatory assets related to power contracts	19,998			22,613
Other regulatory assets	1,014,796			1,034,348
Unrealized gain on derivative instruments	2,877			8,738
Power contract acquisition adjustment gain	163,588			241,648
Other	65,138			58,109
Total other long-term and regulatory assets	1,342,503			1,442,025
Total assets	$	13,280,439		$	13,266,380

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

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) CAPITALIZATION AND LIABILITIES
	September 30, 2017			December 31, 2016
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	571,588			413,468
Accumulated other comprehensive income (loss), net of tax	(33,312		)	(33,712		)
Total common shareholder’s equity	3,847,233			3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,883,064			1,812,480
Debt discount, issuance costs and other	(224,336		)	(234,679		)
Total long-term debt	5,235,000			5,351,661
Total capitalization	9,082,233			9,040,374
Current liabilities:
Accounts payable	296,659			317,043
Short-term debt	139,000			245,763
Current maturities of long-term debt	200,000			2,412
Purchased gas adjustment payable	5,784			—
Accrued expenses:
Taxes	81,354			111,428
Salaries and wages	41,121			49,749
Interest	79,213			73,610
Unrealized loss on derivative instruments	49,820			44,310
Power contract acquisition adjustment loss	2,850			3,159
Other	81,486			71,996
Total current liabilities	977,287			919,470
Other long-term and regulatory liabilities:
Deferred income taxes	1,652,573			1,570,931
Unrealized loss on derivative instruments	15,578			16,261
Regulatory liabilities	611,899			654,622
Regulatory liabilities related to power contracts	179,519			275,061
Power contract acquisition adjustment loss	17,148			19,454
Other deferred credits	744,202			770,207
Total other long-term and regulatory liabilities	3,220,919			3,306,536
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	13,280,439		$	13,266,380

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

7

PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)
	Nine Months Ended September 30,
	2017			2016
Operating activities:
Net income (loss)	$	175,662		$	208,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538			328,809
Conservation amortization	85,847			77,551
Deferred income taxes and tax credits, net	81,899			90,828
Net unrealized (gain) loss on derivative instruments	22,957			(60,785		)
AFUDC – equity	(11,266		)	(10,769		)
Funding of pension liability	(18,000		)	(24,000		)
Regulatory assets and liabilities	(83,370		)	(138,096		)
Other long-term assets and liabilities	8,275			30,766
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	204,477			175,627
Materials and supplies	(2,436		)	(28,448		)
Fuel and natural gas inventory	(2,789		)	(3,222		)
Prepayments and other	7,391			(29,352		)
Purchased gas adjustment	8,569			(10,743		)
Accounts payable	(31,027		)	(22,874		)
Taxes payable	(30,074		)	(36,411		)
Other	(2,983		)	23,391
Net cash provided by (used in) operating activities	768,670			570,346
Investing activities:
Construction expenditures – excluding equity AFUDC	(761,968		)	(507,703		)
Restricted cash	3,116			(1,391		)
Other	5,796			(1,781		)
Net cash provided by (used in) investing activities	(753,056		)	(510,875		)
Financing activities:
Change in short-term debt, net	(106,763		)	12,996
Dividends paid	(17,543		)	(111,592		)
Proceeds from long-term debt and bonds issued	70,583			—
Other	15,999			13,479
Net cash provided by (used in) financing activities	(37,724		)	(85,117		)
Net increase (decrease) in cash and cash equivalents	(22,110		)	(25,646		)
Cash and cash equivalents at beginning of period	28,878			42,494
Cash and cash equivalents at end of period	$	6,768		$	16,848
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	239,566		$	241,351
Cash payments (refunds) for income taxes	1,649			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	87,456		$	58,278

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Operating revenue:
Electric	$	537,543		$	495,321		$	1,736,335		$	1,622,664
Natural gas	111,516			114,458			691,685			601,309
Other	11,318			8,815			29,356			25,487
Total operating revenue	660,377			618,594			2,457,376			2,249,460
Operating expenses:
Energy costs:
Purchased electricity	115,881			94,849			425,263			356,296
Electric generation fuel	66,584			70,503			152,057			165,627
Residential exchange	(14,246		)	(15,577		)	(52,814		)	(49,093		)
Purchased natural gas	32,224			34,041			248,208			205,418
Unrealized (gain) loss on derivative instruments, net	(23		)	6,327			23,098			(57,218		)
Utility operations and maintenance	141,003			138,265			438,622			422,273
Non-utility expense and other	9,994			8,620			27,857			26,474
Depreciation and amortization	120,829			110,022			355,538			328,809
Conservation amortization	25,395			21,800			85,847			77,551
Taxes other than income taxes	66,367			65,268			262,099			235,431
Total operating expenses	564,008			534,118			1,965,775			1,711,568
Operating income (loss)	96,369			84,476			491,601			537,892
Other income (expense):
Other income	6,778			6,131			18,861			19,184
Other expense	(2,878		)	(5,025		)	(6,134		)	(8,488		)
Interest charges:
AFUDC	3,123			2,702			7,853			7,663
Interest expense	(59,868		)	(60,914		)	(180,320		)	(182,336		)
Income (loss) before income taxes	43,524			27,370			331,861			373,915
Income tax (benefit) expense	14,424			8,393			109,015			117,533
Net income (loss)	$	29,100		$	18,977		$	222,846		$	256,382

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net income (loss)	$	29,100	$	18,977	$	222,846	$	256,382
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $939, $1,422, $3,813 and $3,942, respectively	1,744		2,642		7,083		7,322
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $128 and $128, respectively	79		79		237		237
Other comprehensive income (loss)	1,823		2,721		7,320		7,559
Comprehensive income (loss)	$	30,923	$	21,698	$	230,166	$	263,941

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

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	September 30, 2017			December 31, 2016
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):
Electric plant	$	10,036,204		$	9,813,169
Natural gas plant	3,838,533			3,640,271
Common plant	776,116			632,718
Less:  Accumulated depreciation and amortization	(5,149,098		)	(4,927,602		)
Net utility plant	9,501,755			9,158,556
Other property and investments:
Other property and investments	78,332			77,960
Total other property and investments	78,332			77,960
Current assets:
Cash and cash equivalents	5,939			28,481
Restricted cash	9,302			12,418
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively	237,091			344,964
Unbilled revenue	126,252			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	108,814			106,378
Fuel and natural gas inventory, at average cost	59,640			56,851
Unrealized gain on derivative instruments	16,605			54,341
Prepaid expense and other	35,655			43,046
Total current assets	599,298			883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,057			71,517
Power cost adjustment mechanism	4,540			4,531
Other regulatory assets	1,014,804			1,034,352
Unrealized gain on derivative instruments	2,877			8,738
Other	65,138			58,109
Total other long-term and regulatory assets	1,158,416			1,177,247
Total assets	$	11,337,801		$	11,297,080

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

	September 30, 2017			December 31, 2016
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	486,095			359,795
Accumulated other comprehensive income (loss), net of tax	(138,191		)	(145,511		)
Total common shareholder’s equity	3,623,868			3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount, issuance costs and other	(27,043		)	(28,974		)
Total long-term debt	3,549,229			3,744,886
Total capitalization	7,173,097			7,235,134
Current liabilities:
Accounts payable	296,659			317,043
Short-term debt	139,000			245,763
Current maturities of long-term debt	200,000			2,412
Purchased gas adjustment payable	5,784			—
Accrued expenses:
Taxes	81,354			111,428
Salaries and wages	41,121			49,749
Interest	56,254			48,087
Unrealized loss on derivative instruments	49,820			44,170
Other	81,486			71,996
Total current liabilities	951,478			890,648
Other long-term and regulatory liabilities:
Deferred income taxes	1,844,886			1,732,390
Unrealized loss on derivative instruments	15,578			16,261
Regulatory liabilities	610,902			653,296
Other deferred credits	741,860			769,351
Total other long-term and regulatory liabilities	3,213,226			3,171,298
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	11,337,801		$	11,297,080

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)

	Nine Months Ended September 30,
	2017			2016
Operating activities:
Net income (loss)	$	222,846		$	256,382
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538			328,809
Conservation amortization	85,847			77,551
Deferred income taxes and tax credits, net	109,015			116,982
Net unrealized (gain) loss on derivative instruments	23,098			(57,218		)
AFUDC – equity	(11,266		)	(10,769		)
Funding of pension liability	(18,000		)	(24,000		)
Regulatory assets and liabilities	(83,370		)	(138,096		)
Other long-term assets and liabilities	(15,734		)	34,128
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	215,674			175,733
Materials and supplies	(2,436		)	(28,448		)
Fuel and natural gas inventory	(2,789		)	(3,222		)
Prepayments and other	7,391			(29,352		)
Purchased gas adjustment	8,569			(10,743		)
Accounts payable	(31,027		)	(22,874		)
Taxes payable	(30,074		)	(36,411		)
Other	(857		)	22,035
Net cash provided by (used in) operating activities	832,425			650,487
Investing activities:
Construction expenditures – excluding equity AFUDC	(677,004		)	(507,703		)
Restricted cash	3,116			(1,391		)
Other	6,233			2,519
Net cash provided by (used in) investing activities	(667,655		)	(506,575		)
Financing activities:
Change in short-term debt, net	(106,763		)	12,996
Dividends paid	(96,546		)	(195,865		)
Other	15,997			13,510
Net cash provided by (used in) financing activities	(187,312		)	(169,359		)
Net increase (decrease) in cash and cash equivalents	(22,542		)	(25,447		)
Cash and cash equivalents at beginning of period	28,481			41,856
Cash and cash equivalents at end of period	$	5,939		$	16,409
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	160,426		$	162,091
Cash payments (refunds) for income taxes	3,058			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	87,456		$	58,278

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, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and 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 September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger).  As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings.  The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger.  ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.  

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any 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 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. The Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Washington 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.

For Puget Energy, $86.4 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 $76.3 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

Revenue Recognition

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

In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date", deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to early adopt ASU 2014-09 using the original effective date.

14

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

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.

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. The Company is considering whether the new guidance will affect the accounting for purchase power agreements, easements and rights–of–way, utility pole attachments, and other utility industry–related arrangements.

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 will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments 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 will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented and does not anticipate the new guidance will have a material impact on the consolidated statement of cash flows.

Definition of a Business

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

15

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

Retirement 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. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018. For the periods presented in the income statement, the Company’s non-service components for the nine months ended September 30, 2017, was a credit of $13.8 million for Puget Energy and $3.5 million for PSE.  The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

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

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of September 30, 2017, the Company did not have any outstanding interest rate swap instruments.

16

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

Puget Energy and Puget Sound Energy
	At September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Volumes		Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Interest rate swap derivatives3	$	—	$	—	$	—	$450 million	$	—	$	141
Electric portfolio derivatives	*		11,656		39,622		*	36,460		41,329
Natural gas derivatives (MMBtus)4	305.3 million		7,826		25,776		336.4 million	26,619		19,101
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571
Current	**		$	16,605	$	49,820	**	$	54,341	$	44,310
Long-term	**		2,877		15,578		**	8,738		16,261
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571

_______________

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

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

³  Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017, and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

** Not meaningful and/or applicable.

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

17

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 September 30, 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	$	19,482	$	—	$	19,482	$	(12,961	)	$	—		$	6,521
Liabilities:
Energy derivative contracts	65,398		—		65,398		(12,961		)	(739		)	51,698

Puget Energy and Puget Sound Energy
	At December 31, 2016
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—	$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—		17,572
Interest rate swaps2	141		—		141		—			—		141

_______________

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

²  Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

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

Puget Energy and Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2017			2016			2017			2016
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	563		$	28		$	(651	)
	Interest expense	—			(349		)	—			(349		)
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	903			(8,873		)	(20,979		)	41,957
Realized	Electric generation fuel	(6,753		)	(3,194		)	(14,773		)	(36,204		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(880		)	2,546			(2,119		)	15,261
Realized	Purchased electricity	(4,356		)	(1,282		)	(14,434		)	(16,077		)
Total gain (loss) recognized in income on derivatives		$	(11,086	)	$	(10,589	)	$	(52,277	)	$	3,937

_______________

¹ Interest rate swap contracts are only 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 September 30, 2017, approximately 98.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated at least investment grade by rating agencies and 1.5% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of September 30, 2017, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2017, PSE had cash posted as collateral of $1.4 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

19

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 during the nine months ended September 30, 2017 nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At September 30, 2017						At December 31, 2016
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	6,113	$	—	$	6,113	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	27,214		—		—		7,427		—		—
Forward value of contract3	739		1,384		—		507		—		—
Total	$	34,066	$	1,384	$	6,113	$	12,828	$	—	$	4,894

_______________

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

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

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

(4) 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

20

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 $49.4 million and $49.1 million at September 30, 2017 and December 31, 2016, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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

Puget Energy		At September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,101,936		6,439,413		5,091,593		6,337,287
Long-term debt (variable-rate)	2	83,064		83,064		12,480		12,480
Total liabilities		$	5,435,000	$	6,768,709	$	5,354,073	$	6,560,028

Puget Sound Energy		At September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,229		4,465,126		3,497,298		4,360,783
Total liabilities		$	3,749,229	$	4,711,358	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

21

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 September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,106	$	4,550	$	11,656	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	3,794		4,032		7,826		23,316		3,303		26,619
Total assets	$	10,900	$	8,582	$	19,482	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	36,482		3,140		39,622		36,507		4,822		41,329
Natural gas derivative instruments	23,998		1,778		25,776		16,423		2,678		19,101
Total liabilities	$	60,480	$	4,918	$	65,398	$	53,071	$	7,500	$	60,571

_______________

¹  Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

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

Puget Energy and Puget Sound Energy	Three Months Ended September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	643		$	1,456		$	2,099		$	(3,062	)	$	(484	)	$	(3,546	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	2,458			—			2,458			574			—			574
Included in regulatory assets / liabilities	—			2,133			2,133			—			(212		)	(212		)
Settlements	(1,783		)	(1,301		)	(3,084		)	93			84			177
Transferred into Level 3	(1,668		)	—			(1,668		)	(727		)	—			(727		)
Transferred out of Level 3	1,760			(34		)	1,726			2,532			(331		)	2,201
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $0.9 million for the three months ended September 30, 2017 and 2016.

22

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

Puget Energy and Puget Sound Energy	Nine Months Ended September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	3,503			—			3,503			3,228			—			3,228
Included in regulatory assets / liabilities	—			5,715			5,715			—			2,869			2,869
Settlements	(5,622		)	(4,605		)	(10,227		)	(461		)	(1,731		)	(2,192		)
Transferred into Level 3	523			(553		)	(30		)	(2,807		)	—			(2,807		)
Transferred out of Level 3	2,034			1,072			3,106			6,795			302			7,097
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $1.9 millionand $4.0 million for the nine months ended September 30, 2017 and 2016, respectively.

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

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,550	$	3,140	Discounted cash flow	Power prices (per MWh)	$	8.54	$	28.98	$	17.99
Natural gas	$	4,032	$	1,778	Discounted cash flow	Natural gas prices (per MMBtu)	$	0.38	$	3.09	$	2.75

_______________

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, 2016:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	5,794	$	4,822	Discounted cash flow	Power prices (per MWh)	$	11.86	$	33.52	$	27.61
Natural gas	$	3,303	$	2,678	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.00	$	3.24	$	2.42

_______________

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 September 30, 2017 and December 31, 2016, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.7 million and $0.2 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 September 30, 2017, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 3.5% from June 30, 2017, causing an impairment of $1.0 million. As of March 31, 2017, due to significant decreases in forward power prices of 14.1% for years 2017-2022, and 24.4% for years 2023-2035 from December 31, 2016, impairments totaling $80.3 million were recorded to the Company's intangible asset contracts.

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

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	$	14,879	$	13,067	$	1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total year-to-date impairments						$	81,345

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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
September 30, 2017
Wells Hydro	Power prices (per MWh)	$14.06	$26.86	$22.24
	Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017
Wells Hydro	Power prices (per MWh)	$8.76	$26.70	$20.86
	Power contract costs per quarter (in thousands)	3,965	4,223	4,051
Rocky Reach	Power prices (per MWh)	$8.53	$48.21	$27.69
	Power contract costs per quarter (in thousands)	5,827	6,780	6,150
Priest Rapids RP	Power prices (per MWh)	$13.70	$29.38	$23.14
	Power contract costs per year (in thousands)	620	4,022	2,306

(5) 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, all non-represented and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees, along with International Brotherhood of Electrical Workers (IBEW) represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides access to group medical care coverage and legacy life insurance benefits (Other Benefits) for certain retired employees.  These benefits are provided principally through an insurance company.  The group medical insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year.

Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

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The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,945		)	(11,589		)	—		—		(115		)	(112		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—
Amortization of net loss (gain)	—			—			269		228		(101		)	(233		)
Net periodic benefit cost	$	(327	)	$	(44	)	$	1,079	$	1,091	$	(73	)	$	(236	)

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,837		)	(34,964		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,485		)	(1,485		)	33		32		—			—
Amortization of net loss (gain)	—			—			807		683		(302		)	(289		)
Net periodic benefit cost	$	(983	)	$	(748	)	$	3,239	$	3,273	$	(219	)	$	(154	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,965		)	(11,638		)	—		—		(115		)	(112		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,262			3,963			392		333		(160		)	(295		)
Net periodic benefit cost	$	3,017		$	3,972		$	1,202	$	1,196	$	(132	)	$	(298	)

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Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,896		)	(35,110		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,180		)	(1,180		)	33		33		—			—
Amortization of net loss (gain)	9,786			11,443			1,175		997		(480		)	(474		)
Net periodic benefit cost	$	9,049		$	10,854		$	3,607	$	3,588	$	(397	)	$	(339	)

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2017 and December 31, 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Nine Months Ended			Year Ended			Nine Months Ended			Year Ended			Nine Months Ended			Year Ended
(Dollars in Thousands)	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	15,060			18,913			685			1,085			54			93
Interest cost	21,279			28,689			1,714			2,325			375			533
Actuarial loss (gain)	(253		)	1,545			—			106			373			(2,262		)
Benefits paid	(31,344		)	(38,730		)	(1,428		)	(3,061		)	(857		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative Expense	—			(898		)	—			—			—			—
Benefit obligation at end of period	$	657,349		$	652,607		$	52,705		$	51,734		$	11,239		$	11,194

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, 2017 are expected to be at least $18.0 million, $1.9 million and $0.3 million, respectively. During the three months ended September 30, 2017, the Company made no contributions to fund the qualified pension plan, as the aggregate funding for the year has already been reached for the year ending December 31, 2017. During the three months ended September 30, 2017, the Company contributed $0.5 million and $0.1 million to fund the SERP and other postretirement plan, respectively. During the nine months ended September 30, 2017, the Company contributed $18.0 million, $1.4 million and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.

(6) Regulation and Rates

2013 Expedited Rate Filing, Decoupling and Centralia Decision

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

27

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

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%. The requested combined electric tariff changes were a net increase of $86.3 million, or 4.1%, annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by the Washington Commission, would resolve all but four of the contested issues between the settling parties. 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 recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above.

Under the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing party in PSE’s pending GRC is advocating that PSE's decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE's existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms. PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. PSE's decoupling mechanism over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.

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The Washington Commission approved the following PSE requests to change rates 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, 2017	2.0%	$41.9
May 1, 2016	1.0	20.8
Natural Gas:
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 $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.

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

Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)
Natural Gas:
2016	$47.4
2015	28.7

Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for a system average interruption duration index. For the nine months ended September 30, 2017 and 2016, PSE incurred $21.1 million and $15.6 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred to a regulatory asset in 2017 and $6.5 million in 2016.

Power Cost Adjustment Mechanism

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

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The graduated scale that was applicable through December 31, 2016 was as follows:

Annual Power Cost Variability	Company’s Share	Customers' Share
+/- $20 million	100%	—%
+/- $20 million - $40 million	50	50
+/- $40 million - $120 million	10	90
+/- $120 + million	5	95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and applies the following graduated scale:

	Company's Share		Customers' Share
Annual Power Cost 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

The settlement also resulted in the following changes to the PCA mechanism:

• Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

• Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;

• Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);

• Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and

• Establishment of a five-year moratorium on changes to the PCA.

For the nine months ended September 30, 2017, PSE under recovered its power costs by $8.9 million of which no amount was apportioned to customers.  This compares to an over recovery of power costs of $1.4 million for the nine months ended September 30, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.

Electric Conservation Rider

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

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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	0.7%	$16.5
May 1, 2016	(0.5)	(11.7)

Electric Property Tax Tracker Mechanism

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

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

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

Federal Incentive Tracker Tariff

The federal incentive tracker tariff passes through to customers the benefits associated with realized treasury grants and production tax credits. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.

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

Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2018, proposed	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 will be receiving from the Bonneville Power Administration (BPA) between October 1, 2017 and September 30, 2019.  Rates change bi-annually on October 1.

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
October 1, 2017	(0.6)%	$(80.8)
October 1, 2015	2.4	(76.4)

Power Cost Update Compliance Filing

The power cost update compliance filing is an update to a limited-scope proceeding to periodically reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission’s Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC.

The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2016	(1.7)%	$(37.3)

Natural Gas Regulation and Rates

Natural Gas Conservation Rider

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2017	(0.1)%	$(1.0)
May 1, 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 removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes.

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

Natural Gas Cost Recovery Mechanism

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2017	0.5%	$4.9
November 1, 2016	0.6	5.6

Purchased Gas Adjustment

PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.

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

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

(7) Asset Retirement Obligations

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, and natural gas mains where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).

On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments.

The CCR rule and two new agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations. The

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changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.

On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional costs, such as, monitoring, water treatment, forced evaporation and post-closure care for all Colstrip Units. As a result, in 2016 the Company increased the Colstrip ARO ending liability by $45.7 million for Colstrip Units 1 and 2 and $37.0 million for Colstrip Units 3 and 4.

The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. The Company will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.

For the nine months ended September 30, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $1.5 million for PSE and $1.4 million for Puget LNG in September 2017.

The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Changes in ARO
Balance at December 31, 2016	$	200,345
New asset retirement obligation recognized in the period1	2,881
Liability adjustments	(1,035		)
Revisions in estimated cash flows	(18,462		)
Accretion expense	4,126
Balance at September 30, 2017	$	187,855

_______________

^{1  New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.} 

(8) Commitment and Contingencies

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. 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) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. Due to a re-estimate of Colstrip Units 1 and 2 ARO costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood

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

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

Other Commitments and Contingencies

The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company recorded reserves of $0.6 million and $0.7 million relating to these claims as of September 30, 2017 and December 31, 2016, respectively.

In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, during the nine months ended September 30, 2017, the Company entered into new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2016. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the U.S. Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and 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 I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and 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;

• Availability and access to capital and the cost of capital;

• Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;

• Wholesale commodity prices of electricity and natural gas;

• Increasing capital expenditures with additional depreciation and amortization;

• Bonus depreciation and the impact on rate base;

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

• Federal, state, and local taxes.

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

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2017 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). 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 on a regular and frequent basis in the foreseeable future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that 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.

General Rate Case Filing

On January 13, 2017, PSE filed its general rate case (GRC) with the Washington Commission which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%. The requested combined electric tariff changes were a net increase of $86.3 million, or 4.1%, annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. It also requested that electric energy supply

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fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an Expedited Rate Filing (ERF) that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by the Washington Commission, would resolve all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% 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 recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the power cost adjustment (PCA) and purchased gas adjustment (PGA) mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above.

Under the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing Party in PSE’s pending GRC is advocating that PSE’s decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE’s existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms.

PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. The decoupling mechanism over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.

On April 28, 2017, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2017. The overall changes represent a rate increase for electric customers of $41.9 million, or 2.0%, annually, and a rate increase for natural gas customers of $22.4 million, or 2.4%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2016. As a result, PSE filed with the Washington Commission a reduction in electric decoupling deferral and revenue of $11.9 million and a reduction in natural gas decoupling deferral and revenue of $2.2 million. This was included as a reduction to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2017 rate increase is $47.4 million for natural gas revenue that was accrued through December 31, 2016. The amount not recovered in 2017 may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  

Due to the 3.0% cap on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet, PSE performed an analysis as of September 30, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period.  The analysis indicated all current deferred revenues for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 decoupling revenues other than to record the previously unrecognized decoupling deferrals of $20.8 million.

Other Proceedings

Microsoft

On October 7, 2016, PSE filed a tariff to provide open access service to a narrow set of qualifying customers. Subsequent to that tariff filing, parties to the case reached an all-party settlement that would convert the tariff to a special contract only allowing retail access for the loads of the Microsoft Corporation currently being served under PSE’s electric Schedule 40. The special

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

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 energy choices to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh) and government customers. Approximately 135 MW of new wind generation facilities will be constructed in the region by a developer under contract to PSE which will meet the demand for this voluntary renewable energy product project.

Electric Rates

Power Cost Adjustment Mechanism

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

The graduated scale that was applicable through December 31, 2016 was as follows:

Annual Power Cost Variability	Company's Share	Customers’ Share
+/- $20 million	100%	—%
+/- $20 million - $40 million	50	50
+/- $40 million - $120 million	10	90
+/- $120 + million	5	95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and applies the following scale:

	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

The settlement also resulted in the following changes to the PCA mechanism:

• Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

• Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;

• Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);

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• Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and

• Establishment of a five-year moratorium on changes to the PCA.

On September 30, 2016, PSE filed an accounting petition with the Washington Commission which requests 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 is January 1, 2017 through December 31, 2017 when rates go into effect from PSE's 2017 GRC.  On November 10, 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition.

For the nine months ended September 30, 2017, PSE under recovered its power costs by $8.9 million of which no amount was apportioned to customers.  This compares to an over recovery of power costs of $1.4 million for the nine months ended September 30, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.

Electric Conservation Rider

On April 28, 2017, the Washington Commission approved PSE's request to change rates under its electric conservation rider mechanism, effective May 1, 2017. The rate filing requests recovery of estimated program year expenditures as well as a true-up for actual costs and collections for the conservation program for the prior period which would result in a rate increase for electric customers of $16.5 million, or 0.7%, annually.

Electric Property Tax Tracker Mechanism

On April 28, 2017, the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism, effective May 1, 2017.  The approved filing incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year which would result in a rate decrease for electric customers of $0.9 million, or 0.04%, annually.

Federal Incentive Tracker Tariff

On October 31, 2017, PSE filed with the Washington Commission an annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2018. The proposed true-up filing, as originally filed, resulted in a total credit of $48.2 million to be passed back to eligible customers over the twelve months beginning January 1, 2018. The total credit includes $37.8 million which represents the pass-back of grant amortization and $10.4 million represents the pass through of interest. This filing represents an overall average rate increase of 0.2%, annually.

On December 22, 2016, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2017. The true-up filing resulted in a total credit of $51.7 million to be passed back to eligible customers over the twelve months beginning January 1, 2017.  The total credit includes $38.1 million which represents the pass-back of grant amortization and $13.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2016 rate period.  This filing represents an overall average rate increase of 0.3%, annually.

Residential Exchange Benefit

On September 28, 2017, the Washington Commission approved the rate filing to PSE's Residential Exchange Benefit Tariff, with an effective date of October 1, 2017. The filing resulted in a total credit of $80.8 million to be passed back to eligible customers over the twelve months beginning October 1, 2017.  This filing represents an overall average rate decrease of 0.6%, annually.

On September 24, 2015, the Washington Commission approved the rate filing to PSE's Residential Exchange Benefit Tariff, with an effective date of October 1, 2015. The filing resulted in a total credit of $76.4 million to be passed back to eligible customers over the twelve months beginning October 1, 2015.  This filing represents an overall average rate increase of 2.4%, annually.

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Power Cost Update Compliance Filing

On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission's Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC. The filing requested a reduction in Schedule 95 rates of $37.3 million or an overall rate decrease of 1.7% annually. A corresponding reduction in the PCA Mechanism Baseline Rate used to track the PCA imbalance for sharing was also requested in this filing. PSE’s rate filing became effective on December 1, 2016 by operation of law.

Natural Gas Rates

Natural Gas Conservation Rider

On April 28, 2017, the Washington Commission approved PSE's annual filing request to change rates under its natural gas conservation rider mechanism, effective May 1, 2017. The rate filing requests recovery of estimated program year expenditures as well as a true-up for actual costs and collections for the conservation program for the prior period which would result in a rate decrease for natural gas customers of $1.0 million, or 0.1%, annually.

Natural Gas Property Tax Tracker Mechanism

On April 28, 2017, the Washington Commission approved PSE's annual filing request to change rates under its natural gas property tax tracker mechanism, effective May 1, 2017, which would result in a rate decrease for natural gas customers of $1.1 million, or 0.1%, annually.

Natural Gas Cost Recovery Mechanism

On October 26, 2017, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2017. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system.  The impact to the CRM rates is an annual revenue increase of $4.9 million, or 0.5%, annually.

On October 27, 2016, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2016. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system.  The impact to the CRM rates is an annual revenue increase of $5.6 million, or 0.6%, annually.

Purchased Gas Adjustment

On October 26, 2017, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2017, which reflects changes in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $30.8 million, or 3.3%, annually with no impact on net operating income.

On October 27, 2016, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2016, which reflects changes in wholesale natural gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $4.1 million, or 0.4%, annually with no impact on net operating income.

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

Other Factors and Trends

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. As of September 30, 2017, PSE's credit facilities

40

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

Regulatory Compliance Costs and Expenditures

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

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

Other Challenges and Strategies

Competition

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

Results of Operations

Puget Sound Energy

Non-GAAP Financial Measures - Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), 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 to maintain electric and natural gas margins to ultimately provide adequate recovery of operating costs, including interest and equity returns.  PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural gas margin measures.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

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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 table displays the details of PSE's electric margin changes:

Electric Margin	Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Electric operating revenue:
Residential sales	$	239,279		$	224,987		$	14,292		$	877,112		$	801,163		$	75,949
Commercial sales	215,392			214,632			760			656,462			644,025			12,437
Industrial sales	27,836			29,740			(1,904		)	83,417			84,417			(1,000		)
Other retail sales	4,839			5,031			(192		)	14,534			15,234			(700		)
Total retail sales	487,346			474,390			12,956			1,631,525			1,544,839			86,686
Transportation sales	3,422			2,464			958			9,136			8,086			1,050
Sales to other utilities and marketers	23,716			20,494			3,222			38,404			38,032			372
Decoupling revenue	13,310			(277		)	13,587			24,889			34,199			(9,310		)
Other decoupling revenue1	(4,008		)	(11,863		)	7,855			(11,704		)	(14,525		)	2,821
Other	13,757			10,113			3,644			44,085			12,033			32,052
Total electric operating revenues2	537,543			495,321			42,222			1,736,335			1,622,664			113,671
Minus electric energy costs:
Purchased electricity2	115,881			94,849			21,032			425,263			356,296			68,967
Electric generation fuel2	66,584			70,503			(3,919		)	152,057			165,627			(13,570		)
Residential exchange2	(14,246		)	(15,577		)	1,331			(52,814		)	(49,093		)	(3,721		)
Total electric energy costs	168,219			149,775			18,444			524,506			472,830			51,676
Electric margin3	$	369,324		$	345,546		$	23,778		$	1,211,829		$	1,149,834		$	61,995
Electric Energy Sales, MWh
Residential sales	2,081,223			1,997,675			83,548			7,785,631			7,173,224			612,407
Commercial sales	2,272,185			2,266,420			5,765			6,784,797			6,637,349			147,448
Industrial sales	316,051			334,108			(18,057		)	913,647			925,280			(11,633		)
Other retail sales	19,879			23,271			(3,392		)	64,217			69,366			(5,149		)
Total energy sales to customers	4,689,338			4,621,474			67,864			15,548,292			14,805,219			743,073

___________________

¹  Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.

²  As reported on PSE’s Consolidated Statement of Income.

³  Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.

Three Months Ended September 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased $42.2 million primarily due to decoupling revenue of $13.6 million, higher retail sales of $13.0 million, other decoupling revenue of $7.9 million and other electric operating revenues of $3.6 million.  These items are discussed in detail below.

• Electric retail sales increased $13.0 million primarily due to a $7.0 million increase in retail electricity usage of 67,864 Megawatt Hour (MWhs) related to average retail customer growth of 13,828 customers, or 1.2%; and an increase in rates of $6.0 million.

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• Decoupling revenue increased $13.6 million due to an increase of $15.7 million in decoupling revenue associated with the fixed cost deferral of the PCA mechanism in 2017. This was partially offset by $2.1 million in lower decoupling deferrals in 2017 compared to 2016 due to higher electricity usage, as noted above.

• Other decoupling revenue increased $7.9 million due to reduced sharing of rate of return (ROR) excess earnings of $10.2 million from over earnings in 2016 as compared to no earnings sharing in 2017. This was partially offset by an increase of decoupling cash collections of $1.1 million as compared to 2016 due to an additional $9.0 million being set into rates.

• Other electric operating revenue increased $3.6 million primarily due to generation of a production tax credit (PTC) deferral of $5.0 million in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017. This was partially offset by a decrease in net wholesale natural gas sales of $1.8 million.

Electric Energy Costs

• Purchased electricity expense increased $21.0 million primarily due to a $13.9 million increase primarily related to long-term purchases and a $4.9 million increase in energy imbalance market (EIM) purchases. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind production of 21.3% and lower production at the combustion turbines of 7.8% resulted in the need to purchase power. PSE began participating in the EIM operated by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand and generation resources.

• Electric generation fuel expense decreased $3.9 million due to a number of factors including a $3.3 million decrease in the total cost of natural gas burned driven by lower volumes burned in 2017 as compared to 2016. Also contributing to the decrease in fuel costs is a $3.4 million decrease in the cost of coal burned from lower average prices offset by a $1.9 million increase in the lower of cost or market inventory adjustment for coal recorded in 2017 compared to 2016.

Nine Months Ended September 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased $113.7 million primarily due to higher retail sales of $86.7 million, other operating revenues of $32.1 million and other decoupling adjustments of $2.8 million; partially offset by decreases in decoupling revenue of $9.3 million. These items are discussed in detail below.

• Electric retail sales increased $86.7 million primarily due to a $77.5 million increase in retail electricity usage of 743,073 MWhs related to a 28.0% increase in heating degree days; and an increase in rates of $9.2 million.

• Decoupling revenue decreased $9.3 million due to $19.8 million in lower decoupling deferrals in 2017 compared to 2016 due to higher electricity usage, as noted above. This was partially offset by an increase of $10.5 million in decoupling revenue associated with the fixed cost deferral of the PCA mechanism in 2017.

• Other decoupling revenue increased $2.8 million primarily due to decreases in ROR excess earnings sharing of $8.6 million due to no expectation to over earn in 2017 and 24-month revenue reserve of $1.6 million from no reserve in 2017. This was partially offset by a $7.4 million increase of decoupling cash collections as compared to 2016 due to an additional $9.0 million being set into rates.

• Other electric operating revenue increased $32.1 million primarily due to an increase in net wholesale natural gas sales of $17.3 million and a PTC deferral of $15.8 million in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017.

Electric Energy Costs

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

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• Electric generation fuel expense decreased $13.6 million primarily due to a $10.7 million decrease in the total cost of natural gas burned driven by lower volumes burned offset by an increase in the average price of the natural gas burned and a $2.9 million decrease in the cost of coal burned due to a lower average prices of coal burned in 2017 compared to 2016. 

• Residential exchange credits increased $3.7 million resulting from increased electricity usage as rates remain consistent in both periods. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income. The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

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 following table displays the details of PSE's natural gas margin:

Natural Gas Margin	Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Natural gas operating revenue:
Residential sales	$	65,793		$	66,480		$	(687	)	$	467,725		$	376,310		$	91,415
Commercial sales	36,617			36,862			(245		)	194,716			162,135			32,581
Industrial sales	3,390			3,349			41			15,258			13,742			1,516
Total retail sales	105,800			106,691			(891		)	677,699			552,187			125,512
Transportation sales	5,285			4,897			388			16,218			15,007			1,211
Decoupling revenue	4,840			3,709			1,131			1,482			39,739			(38,257		)
Other decoupling revenue1	(7,315		)	(3,904		)	(3,411		)	(12,932		)	(14,565		)	1,633
Other	2,906			3,065			(159		)	9,218			8,941			277
Total natural gas operating revenues2	111,516			114,458			(2,942		)	691,685			601,309			90,376
Minus purchased natural gas energy costs2	32,224			34,041			(1,817		)	248,208			205,418			42,790
Natural gas margin3	$	79,292		$	80,417		$	(1,125	)	$	443,477		$	395,891		$	47,586
Natural Gas Volumes
(Therms in Thousands):
Residential	42,150			44,650			(2,500		)	412,325			331,180			81,145
Commercial firm	31,861			31,629			232			194,446			159,096			35,350
Industrial firm	4,048			3,626			422			18,444			16,015			2,429
Interruptible	6,877			9,452			(2,575		)	33,921			33,829			92
Total retail natural gas volumes, therms	84,936			89,357			(4,421		)	659,136			540,120			119,016
Transportation volumes	53,992			52,298			1,694			173,042			170,548			2,494
Total natural gas volumes	138,928			141,655			(2,727		)	832,178			710,668			121,510

_______________

¹  Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.

²  As reported on PSE’s Consolidated Statement of Income.

³  Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.

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Three Months Ended September 30, 2017 compared to 2016

Natural Gas Operating Revenue

Natural gas operating revenue decreased $2.9 million primarily due to a decrease of $3.4 million in other decoupling revenue and a decrease of $0.9 million in total retail sales due to a decrease of natural gas usage; partially offset by a $1.1 million increase in decoupling revenue. These items are discussed in detail below.

• Natural gas retail sales revenue decreased $0.9 million primarily due to a decrease of $5.3 million from a reduction of 2,727 therms sold from lower heating degree days in 2017; partially offset by an increase of $4.4 million due to rate adjustments.

• Other decoupling revenue decreased $3.4 million primarily due to increased ROR excess earnings sharing of $6.2 million of which $4.3 million was accrued for over earnings in 2017. This was partially offset by a decrease of $2.7 million in 24-month revenue reserve as compared to 2016 as no reserve was recorded in 2017.

Nine Months Ended September 30, 2017 compared to 2016

Natural Gas Operating Revenue

Natural gas operating revenue increased $90.4 million primarily due to an increase of $125.5 million in total retail sales due to additional natural gas usage and an increase in other decoupling revenue of $1.6 million; partially offset by a $38.3 million reduction in decoupling revenue. These items are discussed in detail below.

• Natural gas retail sales revenue increased $125.5 million primarily due to an increase of $121.7 million from an additional 121,510 therms sold related to a 28.0% increase in heating degree days; and an increase of $3.8 million due to rate adjustments.

• Decoupling revenue decreased $38.3 million due to lower load volumes in 2016, which caused actual revenue to be below the allowed revenue, resulting in higher decoupling revenue of $39.7 million. In 2017, higher load volumes caused actual revenue to be closer to allowed revenue resulting in lower decoupling revenue of $1.5 million.

• Other decoupling revenue increased $1.6 million primarily due to a $22.9 million reversal of previously deferred revenues related to the 24-month revenue reserve.  The increase was partially offset by an increase in decoupling cash collections of $13.0 million due to an additional $6.0 million being set in rates and increased ROR excess earnings sharing of $8.2 million of which $10.1 million was accrued for over earnings in 2017.

Natural Gas Energy Costs

Purchased natural gas expense increased $42.8 million directly related to a 22.7% increase in natural gas usage.

Other Operating Expenses and Other Income (Deductions)

The following table displays the details of PSE's operating expenses and other income (deductions) for the three and nine months ended September 30, 2017 and 2016:

Puget Sound Energy	Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Operating expenses:
Net unrealized (gain) loss on derivative instruments	$	(23	)	$	6,327		$	(6,350	)	$	23,098		$	(57,218	)	$	80,316
Utility operations and maintenance	141,003			138,265			2,738			438,622			422,273			16,349
Non-utility expense and other	9,994			8,620			1,374			27,857			26,474			1,383
Depreciation and amortization	120,829			110,022			10,807			355,538			328,809			26,729
Conservation amortization	25,395			21,800			3,595			85,847			77,551			8,296
Taxes other than income taxes	66,367			65,268			1,099			262,099			235,431			26,668
Other income (deductions):
Other income	6,778			6,131			647			18,861			19,184			(323		)
Other expense	(2,878		)	(5,025		)	2,147			(6,134		)	(8,488		)	2,354
Interest expense	(56,745		)	(58,212		)	1,467			(172,467		)	(174,673		)	2,206
Income tax expense	14,424			8,393			6,031			109,015			117,533			(8,518		)

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Three Months Ended September 30, 2017 compared to 2016

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments increased $6.4 million from a loss of $6.3 million due to a $6.6 million increase in settlements of contracts with previously unrealized losses.

• Depreciation and amortization expense increased $10.8 million primarily due to an increase of $3.7 million of amortization expense related to an increase of computer software assets, $2.2 million of depreciation expense related to net additions of $183.0 million of electric distribution and general assets and an increase of $1.7 million related to an additional $174.8 million of natural gas distribution assets.

Other Income, Interest Expense and Income Tax Expense

• Income tax expense increased $6.0 million primarily driven by higher pre-tax book income.

Nine Months Ended September 30, 2017 compared to 2016

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments decreased $80.3 million to a loss of $23.1 million of which $57.2 million was due to decreases in average forward market prices of wholesale electricity and natural gas, and $23.1 million due to a decrease in settlements of contracts with previously unrealized losses.

• Utility operations and maintenance expense increased $16.3 million, which was primarily due to the following: increases in administrative and general and customer service expense of $21.9 million primarily due to $7.1 million of rent expense primarily at the corporate office locations, $5.3 million expense primarily for liability claims and insurance premium, $4.6 million of pensions and benefits expense, $3.9 million of general plant maintenance expense and $3.1 million of outside services employed expenses. This was partially offset by a decrease in electric transmission and distribution expense of $8.4 million.

• Depreciation and amortization expense increased $26.7 million primarily due to an increase of $11.6 million of amortization expense related to an increase of computer software assets, $8.7 million of depreciation expense due to net additions of $253.7 million of electric transmission, distribution and general assets and an increase of $5.0 million of depreciation expense due to net additions of $174.8 million of natural gas distribution assets.

• Taxes other than income taxes increased $26.7 million primarily due to increases in municipal taxes of $9.2 million and state excise taxes of $8.5 million both related to increased revenue and an increase of $8.8 million in property taxes related to increased property values and expected tax rates.

Other Income, Interest Expense and Income Tax Expense

• Income tax expense decreased $8.5 million primarily driven by lower pre-tax book income.

Puget Energy

Primarily, all operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and nine months ended September 30, 2017 and 2016 are as follows:

Benefit/(Expense)	Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
PSE net income	$	29,100		$	18,977		$	10,123		$	222,846		$	256,382		$	(33,536	)
Non-utility expense and other	2,675			3,912			(1,237		)	9,200			10,956			(1,756		)
Other income (deductions)	374			(316		)	690			512			(316		)	828
Non-hedged interest rate swap (expense)	—			563			(563		)	28			(651		)	679
Interest expense1	(28,913		)	(28,384		)	(529		)	(85,451		)	(84,451		)	(1,000		)
Income tax benefit (expense)	9,600			7,583			2,017			28,527			26,154			2,373
Puget Energy net income (loss)	$	12,836		$	2,335		$	10,501		$	175,662		$	208,074		$	(32,412	)

_______________

¹  Puget Energy’s interest expense includes elimination adjustments of intercompany interest on long-term debt.

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Summary Results of Operation

Three Months Ended September 30, 2017 compared to 2016

Puget Energy’s net income increased for the three months ended September 30, 2017 by $10.5 million primarily due to PSE's increase in net income. No additional factors significantly impacted Puget Energy's net income.

Nine Months Ended September 30, 2017 compared to 2016

Puget Energy’s net income decreased for the nine months ended September 30, 2017 by $32.4 million primarily due to PSE's decrease in net income. No additional factors significantly impacted Puget Energy's net income.

Capital Requirements

Contractual Obligations and Commercial Commitments

In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, during the nine months ended September 30, 2017 the Company has entered into two new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.

The following are the Company's aggregate availability under commercial commitments as of September 30, 2017:

Puget Sound Energy and Puget Energy	Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2017		2018-2019		2020-2021		Thereafter
PSE working capital facility1	$	650,000		$	—	$	650,000	$	—	$	—
PSE energy hedging facility1	350,000			—		350,000		—		—
Inter-company short-term debt2	30,000			—		—		—		30,000
Total PSE commercial commitments	$	1,030,000		$	—	$	1,000,000	$	—	$	30,000
Puget Energy revolving credit facility3	716,936			—		716,936		—		—
Less: Inter-company short-term debt elimination2,3	(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	$	1,716,936		$	—	$	1,716,936	$	—	$	—

_______________

¹  For more information, see "Financing Program - Puget Sound Energy - Credit Facilities - set forth below

²   For more information, see "Financing Program - Puget Sound Energy - Demand Promissory Note - set forth below.

³  For more information, see "Financing Program - Puget Energy - Credit Facility - set forth below.

Off-Balance Sheet Arrangements

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

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 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 $677.0 million for the nine months ended September 30, 2017. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Thousands)	2017		2018		2019
Total energy delivery, technology and facilities expenditures	$	1,092,000	$	972,000	$	809,000

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

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cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  

Capital Resources

Cash from Operations

Puget Sound Energy	Nine Months Ended September 30, 2017
(Dollars in Millions)	2017			2016			Change
Net income	$	222,846		$	256,382		$	(33,536	)
Non-cash items1	562,232			455,355			106,877
Changes in cash flow resulting from working capital2	164,451			66,718			97,733
Regulatory assets and liabilities	(83,370		)	(138,096		)	54,726
Other noncurrent assets and liabilities3	(33,734		)	10,128			(43,862		)
Net cash provided by operating activities	$	832,425		$	650,487		$	181,938

_______________

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

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

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

Nine Months Ended September 30, 2017 compared to 2016

Cash generated from operations for the nine months ended September 30, 2017 increased by $181.9 million including a net income decrease of $33.5 million. The following are significant factors that impacted PSE's cash flows from operations:

• Cash flow resulting from non-cash items increased $106.9 million primarily due to changes in derivative instruments of $80.3 million and depreciation and amortization of $26.7 million.

• Cash flow resulting from working capital increased $97.7 million due to changes in accounts receivable, unbilled revenue, materials and supplies, prepayments, purchased gas adjustments and accrued expenses.

• Cash flow resulting from regulatory assets and liabilities increased $54.7 million primarily due to changes in decoupling and derivatives offset by changes in purchased gas adjustments.

• Cash flow resulting from other noncurrent assets and liabilities decreased $43.9 million primarily due to changes in asset retirement obligations and pension funding partially offset by changes in long-term deferred credits.

Puget Energy	Nine Months Ended September 30, 2017
(Dollars in Millions)	2017			2016			Change
Net income	$	175,662		$	208,074		$	(32,412	)
Non-cash items1	534,975			425,634			109,341
Changes in cash flow resulting from working capital2	151,128			67,968			83,160
Regulatory assets and liabilities	(83,370		)	(138,096		)	54,726
Other noncurrent assets and liabilities3	(9,725		)	6,766			(16,491		)
Net cash provided by operating activities	$	768,670		$	570,346		$	198,324

_______________

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

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

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

Nine Months Ended September 30, 2017 compared to 2016

Cash generated from operations for the nine months ended September 30, 2017 increased by $198.3 million compared to the same period in 2016.  The net difference was primarily impacted by the increase from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below:

• Cash flow resulting from working capital decreased $14.6 million primarily due to a larger change in accounts receivable.

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• Cash flow resulting from other noncurrent assets and liabilities increased $27.4 million primarily due to changes in other property and investments related to Puget LNG.

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 September 30, 2017, PSE had two unsecured revolving credit facilities which provided, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consisted of a $650.0 million revolving liquidity facility (which included a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including as backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which included an energy hedging letter of credit facility). The $650.0 million liquidity facility included a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also had an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.5 billion. These unsecured revolving credit facilities mature in April 2019.

The credit agreements are syndicated among numerous lenders and contain 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 agreements also contain a financial covenant of total debt to total capitalization of 65.0% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of September 30, 2017, PSE was in compliance with all applicable covenant ratios.

The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow 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 facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.

As of September 30, 2017, no amounts were drawn and outstanding under either facility. No letters of credit were outstanding under either facility, and $139.0 million was outstanding under the commercial paper program. Outside of the credit agreements, 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.

InOctober 2017,PSE entered into a new $800.0 million credit facility to replace the two existing facilities. The new credit facility consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant, and accordion feature remain substantially the same. The new facility matures inOctober 2022.

Demand Promissory Note

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

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Debt Restrictive Covenants

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

PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests at September 30, 2017, PSE could issue:

• Approximately $2.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3 billion of electric bondable property available for issuance, subject to a minimum interest coverage ratio of 2.0 times net earnings available for interest (as defined in the electric utility mortgage) which PSE exceeded at September 30, 2017; and

• Approximately $545.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $908.3 million of natural gas bondable property available for issuance, subject to a minimum combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage) both of which PSE exceeded at September 30, 2017.

At September 30, 2017, PSE had approximately $6.9 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 $800.0 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 September 30, 2017, approximately $674.2 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 49.4% at September 30, 2017 and the EBITDA to interest expense was 5.4 to 1.0 for the twelve months ended September 30, 2017.

PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.

Puget Energy

Credit Facility

At September 30, 2017, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures April 2018. 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 September 30, 2017, there was $83.1 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of September 30, 2017, Puget Energy was in compliance with all applicable covenants.

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In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and accordion feature remain substantially the same. The new facility matures inOctober 2022.

On May 15, 2017, Puget Energy entered into a revolving credit agreement with Puget LNG, a wholly owned subsidiary of Puget Energy. Under the agreement, Puget Energy agreed to loan up to $200.0 million to Puget LNG to finance Puget LNG’s portion of the construction costs of a liquefied natural gas facility located at the Port of Tacoma. The interest rate for amounts borrowed under the agreement is equal to the one month LIBOR rate in effect on the first day of each month plus the applicable margin Puget Energy would pay on loans under its credit facility. Interest under the agreement is due on the first business day of each quarter and Puget LNG may elect to make payment in kind (PIK) interest payments in which the interest due is added to the balance outstanding under the agreement. The maximum balance outstanding under the agreement, including PIK interest, is $200.0 million.

Dividend Payment Restrictions

Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0.  Puget Energy's EBITDA to interest expense was 3.6 to 1.0 for the twelve months ended September 30, 2017

At September 30, 2017, 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 Part 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) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. Due to a re-estimate of Colstrip Units 1 and 2 Asset Retirement and Environmental obligation (ARO) costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood

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

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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 a briefing is scheduled for the end of July 2017. In the meantime, Montana has indicated that they plan to work on and submit a State Implementation Plan for the second planning period.

Coal Combustion Residuals

On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR's) under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.

The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.

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. PSE filed comments on this rule in December 2014. The EPA published a final rule on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, 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 and is currently accepting comment on the proposal. PSE is still reviewing the impact of these developments. However, Washington has moved forward with its own Clean Air Rule (CAR). The potential impacts of the Washington Clean Air Rule are described below.

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.

The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers.

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. While awaiting the outcome of the pending litigation, the Company has undertaken steps to comply with the first compliance period of the CAR, which began on January 1, 2017.

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.

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Currently under construction, the Tacoma LNG facility is expected to be operational in 2019. 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 September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.

Item 3.     Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A - "Quantitative and Qualitative Disclosures about Market Risk" of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Commodity Price Risk

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

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

Counterparty Credit Risk

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

Interest Rate Risk

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

Item 4.     Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of September 30, 2017, 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.

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Changes in Internal Control over Financial Reporting

There were no changes in Puget Energy's internal control over financial reporting that occurred during the period covered by this quarterly report 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 September 30, 2017, 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

There were no changes in Puget Sound Energy's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

In January 2017, Puget Sound Energy implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The new/updated systems were used in preparing financial information for the nine months ended September 30, 2017. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes were being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.

PART II                  OTHER INFORMATION

Item 1.     Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of September 30, 2017.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8, "Commitment and Contingencies" in the Combined Notes to Consolidated Financial Statements in Part I.

Item 1A.     Risk Factors

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

Item 5.                      Other Information

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

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

On November 2, 2017, Mr. King replaces Matthew Marcelia, who the Board appointed to serve as Director, Tax, with the same effective date of November 2, 2017.

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Prior to holding his current positions, Mr. King, 33, was a Senior Manager at PricewaterhouseCoopers LLP, a national public accounting firm, since September 2007 where he audited utility, technology and telecommunication companies. Mr. King received a Bachelor’s degree in Accounting and Finance from Ohio University.

No new agreement will be entered into in connection with Mr. King’s appointment to the position of Controller and Principal Accounting Officer, and in addition to his current compensation package, Mr. King will participate in the Company’s Long Term Incentive Plan and other benefit programs of the Company.

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

Also effective November 2, 2017, the sole shareholder of PSE appointed and elected Barbara Gordon to the Board of Directors of PSE. Initially, Ms. Gordon will not be appointed to any committees of the Board.

Ms. Gordon was most recently the Executive Vice President and Chief Customer Officer of Apptio, which position she held from 2016 through 2017, when she retired. Prior to her service at Apptio, she served as Senior Vice President and Chief Operating Officer at Isilon/EMC from 2013 to 2016 and as Corporate Vice President, Worldwide Customer Service and Support at Microsoft from 2003 to 2013. Ms. Gordon also currently serves as Vice President on the Board of Directors for the Seattle-King County Habitat for Humanity and chairs their Strategy Committee.

The compensation offered to Ms. Gordon for her service as a director of PSE will be the same as that offered to all non-employee independent board members of the Company, pursuant to the director compensation schedule filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

Item 6.     Exhibits

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

55

EXHIBIT INDEX

3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
10.1	Credit Agreement dated October 25, 2017 among Puget Energy Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.1 to Puget Energy's Current Report on Form 8-K, filed in October 31, 2017, Commission File No. 1-16305).
10.2	Credit Agreement dated October 25, 2017 among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, 2017, Commission file No. 1-4393).
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016 and 12 months end September 30, 2017).
12.2*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2012 through 2016 and 12 months ended September 30, 2017).
31.1*	Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*	Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*	Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Financial statements from the Quarterly Report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended September 30, 2017 filed on November 3, 2017 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).

__________________

* Filed herewith.

56

SIGNATURES

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

		PUGET ENERGY, INC. PUGET SOUND ENERGY, INC.
		/s/ Stephen King
		Stephen King Controller & Principal Accounting Officer
Date:	November 3, 2017

57

EX-12.1

													Exhibit 12.1
PUGET ENERGY
STATEMENT SETTING FORTH COMPUTATIONS OF RATIOS OF
EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
	12 Months
	Ended			Years Ended
	September 30,			December 31,
	2017			2016			2015			2014			2013			2012
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	409,801		$	453,103		$	332,954		$	228,820		$	408,136		$	378,546
AFUDC - equity	(13,073		)	(12,576		)	(9,325		)	(7,002		)	(15,930		)	(25,469		)
AFUDC - debt	(9,494		)	(9,304		)	(7,575		)	(5,611		)	(11,261		)	(22,216		)
Total	$	387,234		$	431,223		$	316,054		$	216,207		$	380,945		$	330,861
Fixed charges:
Interest expense	$	344,630		$	355,139		$	356,696		$	367,308		$	392,264		$	392,216
Other interest	13,073			12,576			9,325			7,002			15,930			25,469
Portion of rentals representative of the interest factor (a)	7,986			8,061			8,980			10,732			10,257			10,251
Total	$	365,689		$	375,776		$	375,001		$	385,042		$	418,451		$	427,936
Earnings available for combined fixed charges	$	752,923		$	806,999		$	691,055		$	601,249		$	799,396		$	758,797
Ratio of Earnings to Fixed Charges	2.06x			2.15x			1.84x			1.56x			1.91x			1.77x

(a) 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
	September 30,			December 31,
	2017			2016			2015			2014			2013			2012
Earnings Available For Fixed Charges:
Pre-tax income:
Income from continuing operations before income taxes	$	513,874		$	555,928		$	430,089		$	325,955		$	517,015		$	505,478
AFUDC - equity	(13,073		)	(12,576		)	(9,325		)	(7,002		)	(15,930		)	(25,469		)
AFUDC - debt	(9,494		)	(9,304		)	(7,575		)	(5,611		)	(11,261		)	(22,216		)
Total	$	491,307		$	534,048		$	413,189		$	313,342		$	489,824		$	457,793
Fixed charges:
Interest expense	$	231,473		$	242,983		$	247,571		$	264,926		$	261,377		$	247,013
Other interest	13,073			12,576			9,325			7,002			15,930			25,469
Portion of rentals representative of the interest factor (a)	7,986			8,061			8,980			10,732			10,257			10,251
Total	$	252,532		$	263,620		$	265,876		$	282,660		$	287,564		$	282,733
Earnings available for combined fixed charges	$	743,839		$	797,668		$	679,065		$	596,002		$	777,388		$	740,526
Ratio of Earnings to Fixed Charges	2.95x			3.03x			2.55x			2.11x			2.70x			2.62x

(a) 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.

November 3, 2017

/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.

November 3, 2017

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial 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.

November 3, 2017

/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 endedSeptember 30, 2017 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.

November 3, 2017

/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 endedSeptember 30, 2017 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.

November 3, 2017

/s/ Daniel A. Doyle

Daniel A. Doyle

Senior Vice President and Chief Financial Officer

EX-32.3

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.

November 3, 2017

/s/ Kimberly J. Harris

Kimberly J. Harris

President and Chief Executive Officer

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2017 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	2017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
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	2017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating revenue:
Electric	$ 537,543	$ 495,321	$ 1,736,335	$ 1,622,664
Natural gas	111,516	114,458	691,685	601,309
Other	11,318	8,499	29,356	25,170
Total operating revenue	660,377	618,278	2,457,376	2,249,143
Energy costs:
Purchased electricity	115,881	94,849	425,263	356,296
Electric generation fuel	66,584	70,503	152,057	165,627
Residential exchange	(14,246)	(15,577)	(52,814)	(49,093)
Purchased natural gas	32,224	34,041	248,208	205,418
Unrealized (gain) loss on derivative instruments, net	(23)	6,327	23,098	(57,218)
Utility operations and maintenance	141,003	138,265	438,622	422,273
Non-utility expense and other	7,319	4,708	18,658	15,520
Depreciation and amortization	120,829	110,022	355,538	328,809
Conservation amortization	25,395	21,800	85,847	77,551
Taxes other than income taxes	66,367	65,268	262,099	235,431
Total operating expenses	561,333	530,206	1,956,576	1,700,614
Operating income (loss)	99,044	88,072	500,800	548,529
Other income (deductions):
Other income	7,151	6,130	19,375	19,187
Other expense	(2,878)	(5,025)	(6,134)	(8,488)
Non-hedged interest rate swap (expense) income	0	563	28	(651)
Interest charges:
AFUDC	3,123	2,702	7,853	7,663
Interest expense	(88,780)	(89,297)	(265,771)	(266,786)
Income (loss) before income taxes	17,660	3,145	256,151	299,454
Income tax (benefit) expense	4,824	810	80,489	91,380
Net income (loss)	12,836	2,335	175,662	208,074
Subsidiaries [Member]
Operating revenue:
Electric	537,543	495,321	1,736,335	1,622,664
Natural gas	111,516	114,458	691,685	601,309
Other	11,318	8,815	29,356	25,487
Total operating revenue	660,377	618,594	2,457,376	2,249,460
Energy costs:
Purchased electricity	115,881	94,849	425,263	356,296
Electric generation fuel	66,584	70,503	152,057	165,627
Residential exchange	(14,246)	(15,577)	(52,814)	(49,093)
Purchased natural gas	32,224	34,041	248,208	205,418
Unrealized (gain) loss on derivative instruments, net	(23)	6,327	23,098	(57,218)
Utility operations and maintenance	141,003	138,265	438,622	422,273
Non-utility expense and other	9,994	8,620	27,857	26,474
Depreciation and amortization	120,829	110,022	355,538	328,809
Conservation amortization	25,395	21,800	85,847	77,551
Taxes other than income taxes	66,367	65,268	262,099	235,431
Total operating expenses	564,008	534,118	1,965,775	1,711,568
Operating income (loss)	96,369	84,476	491,601	537,892
Other income (deductions):
Other income	6,778	6,131	18,861	19,184
Other expense	(2,878)	(5,025)	(6,134)	(8,488)
Interest charges:
AFUDC	3,123	2,702	7,853	7,663
Interest expense	(59,868)	(60,914)	(180,320)	(182,336)
Income (loss) before income taxes	43,524	27,370	331,861	373,915
Income tax (benefit) expense	14,424	8,393	109,015	117,533
Net income (loss)	$ 29,100	$ 18,977	$ 222,846	$ 256,382

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Parent [Line Items]
Net income (loss)	$ 12,836	$ 2,335	$ 175,662	$ 208,074
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(266)	(29)	400	(400)
Other comprehensive income (loss)	(266)	(29)	400	(400)
Comprehensive income (loss)	12,570	2,306	176,062	207,674
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	29,100	18,977	222,846	256,382
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,744	2,642	7,083	7,322
Amortization of treasury interest rate swaps to earnings, net of tax	79	79	237	237
Other comprehensive income (loss)	1,823	2,721	7,320	7,559
Comprehensive income (loss)	$ 30,923	$ 21,698	$ 230,166	$ 263,941

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ (143)	$ (16)	$ 216	$ (216)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	0
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	939	1,422	3,813	3,942
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	0
Amortization of treasury interest rate swaps to earnings, net of tax	$ 43	$ 43	$ 128	$ 128

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,918,877	$ 7,673,772
Natural gas plant	3,253,977	3,051,586
Common plant	738,409	594,994
Less: Accumulated depreciation and amortization	(2,409,508)	(2,161,796)
Net utility plant	9,501,755	9,158,556
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	166,996	106,418
Total other property and investments	1,823,509	1,762,931
Current assets:
Cash and cash equivalents	6,768	28,878
Restricted cash	9,302	12,418
Accounts receivable, net of allowance for doubtful accounts	232,699	329,375
Unbilled revenue	126,252	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	108,814	106,378
Fuel and gas inventory, at average cost	60,645	58,181
Unrealized gain on derivative instruments	16,605	54,341
Prepaid expense and other	35,655	43,046
Power contract acquisition adjustment gain	15,932	33,413
Total current assets	612,672	902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,566	72,038
Power cost adjustment mechanism	4,540	4,531
Regulatory assets related to power contracts	19,998	22,613
Other regulatory assets	1,014,796	1,034,348
Derivative Asset, Noncurrent	2,877	8,738
Power contract acquisition adjustment gain	163,588	241,648
Other	65,138	58,109
Total other long-term and regulatory assets	1,342,503	1,442,025
Total assets	13,280,439	13,266,380
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	571,588	413,468
Accumulated other comprehensive income (loss), net of tax	(33,312)	(33,712)
Total common shareholder's equity	3,847,233	3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,883,064	1,812,480
Debt discount, issuance costs and other	(224,336)	(234,679)
Total long-term debt	5,235,000	5,351,661
Total capitalization	9,082,233	9,040,374
Current liabilities:
Accounts payable	296,659	317,043
Short-term debt	139,000	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment liability	5,784	0
Accrued expenses:
Taxes	81,354	111,428
Salaries and wages	41,121	49,749
Interest	79,213	73,610
Unrealized loss on derivative instruments	49,820	44,310
Power contract acquisition adjustment loss	2,850	3,159
Other	81,486	71,996
Total current liabilities	977,287	919,470
Long-term and regulatory liabilities:
Deferred income taxes	1,652,573	1,570,931
Unrealized loss on derivative instruments	15,578	16,261
Regulatory liabilities	611,899	654,622
Regulatory liabilities related to power contracts	179,519	275,061
Power contract acquisition adjustment loss	17,148	19,454
Other deferred credits	744,202	770,207
Total long-term and regulatory liabilities	3,220,919	3,306,536
Commitments and contingencies (Note 8)
Total capitalization and liabilities	13,280,439	13,266,380
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	10,036,204	9,813,169
Natural gas plant	3,838,533	3,640,271
Common plant	776,116	632,718
Less: Accumulated depreciation and amortization	(5,149,098)	(4,927,602)
Net utility plant	9,501,755	9,158,556
Other property and investments:
Other property and investments	78,332	77,960
Total other property and investments	78,332	77,960
Current assets:
Cash and cash equivalents	5,939	28,481
Restricted cash	9,302	12,418
Accounts receivable, net of allowance for doubtful accounts	237,091	344,964
Unbilled revenue	126,252	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	108,814	106,378
Fuel and gas inventory, at average cost	59,640	56,851
Unrealized gain on derivative instruments	16,605	54,341
Prepaid expense and other	35,655	43,046
Total current assets	599,298	883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,057	71,517
Power cost adjustment mechanism	4,540	4,531
Other regulatory assets	1,014,804	1,034,352
Derivative Asset, Noncurrent	2,877	8,738
Other	65,138	58,109
Total other long-term and regulatory assets	1,158,416	1,177,247
Total assets	11,337,801	11,297,080
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Earnings reinvested in the business	486,095	359,795
Accumulated other comprehensive income (loss), net of tax	(138,191)	(145,511)
Total common shareholder's equity	3,623,868	3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount, issuance costs and other	(27,043)	(28,974)
Total long-term debt	3,549,229	3,744,886
Total capitalization	7,173,097	7,235,134
Current liabilities:
Accounts payable	296,659	317,043
Short-term debt	139,000	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment liability	5,784	0
Accrued expenses:
Taxes	81,354	111,428
Salaries and wages	41,121	49,749
Interest	56,254	48,087
Unrealized loss on derivative instruments	49,820	44,170
Other	81,486	71,996
Total current liabilities	951,478	890,648
Long-term and regulatory liabilities:
Deferred income taxes	1,844,886	1,732,390
Unrealized loss on derivative instruments	15,578	16,261
Regulatory liabilities	610,902	653,296
Other deferred credits	741,860	769,351
Total long-term and regulatory liabilities	3,213,226	3,171,298
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$ 11,337,801	$ 11,297,080

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
ASSETS
Construction work in progress	$ 598,790	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 6,088	$ 9,798
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	$ 598,790	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 6,088	$ 9,798
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

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities:
Net income (loss)	$ 175,662	$ 208,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538	328,809
Conservation amortization	85,847	77,551
Deferred income taxes and tax credits, net	81,899	90,828
Net unrealized (gain) loss on derivative instruments	22,957	(60,785)
AFUDC – equity	(11,266)	(10,769)
Funding of pension liability	(18,000)	(24,000)
Regulatory Assets	(83,370)	(138,096)
Other long-term assets and liabilities	8,275	30,766
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	204,477	175,627
Materials and supplies	(2,436)	(28,448)
Fuel and gas inventory	(2,789)	(3,222)
Prepayments and other	7,391	(29,352)
Purchased gas adjustment	8,569	(10,743)
Accounts payable	(31,027)	(22,874)
Taxes payable	(30,074)	(36,411)
Other	(2,983)	23,391
Net cash provided by (used in) operating activities	768,670	570,346
Investing activities:
Construction expenditures - excluding equity AFUDC	(761,968)	(507,703)
Restricted cash	3,116	(1,391)
Other	5,796	(1,781)
Net cash provided by (used in) investing activities	(753,056)	(510,875)
Financing activities:
Change in short-term debt, net	(106,763)	12,996
Dividends paid	(17,543)	(111,592)
Proceeds from long-term debt and bonds issued	70,583	0
Other	15,999	13,479
Net cash provided by (used in) financing activities	(37,724)	(85,117)
Net increase (decrease) in cash and cash equivalents	(22,110)	(25,646)
Cash and cash equivalents at beginning of period	28,878	42,494
Cash and cash equivalents at end of period	6,768	16,848
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	239,566	241,351
Cash payments (refunds) for income taxes	1,649	0
Accounts payable for capital expenditures eliminated from cash flows	87,456	58,278
Subsidiaries [Member]
Operating activities:
Net income (loss)	222,846	256,382
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538	328,809
Conservation amortization	85,847	77,551
Deferred income taxes and tax credits, net	109,015	116,982
Net unrealized (gain) loss on derivative instruments	23,098	(57,218)
AFUDC – equity	(11,266)	(10,769)
Funding of pension liability	(18,000)	(24,000)
Regulatory Assets	(83,370)	(138,096)
Other long-term assets and liabilities	(15,734)	34,128
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	215,674	175,733
Materials and supplies	(2,436)	(28,448)
Fuel and gas inventory	(2,789)	(3,222)
Prepayments and other	7,391	(29,352)
Purchased gas adjustment	8,569	(10,743)
Accounts payable	(31,027)	(22,874)
Taxes payable	(30,074)	(36,411)
Other	(857)	22,035
Net cash provided by (used in) operating activities	832,425	650,487
Investing activities:
Construction expenditures - excluding equity AFUDC	(677,004)	(507,703)
Restricted cash	3,116	(1,391)
Other	6,233	2,519
Net cash provided by (used in) investing activities	(667,655)	(506,575)
Financing activities:
Change in short-term debt, net	(106,763)	12,996
Dividends paid	(96,546)	(195,865)
Other	15,997	13,510
Net cash provided by (used in) financing activities	(187,312)	(169,359)
Net increase (decrease) in cash and cash equivalents	(22,542)	(25,447)
Cash and cash equivalents at beginning of period	28,481	41,856
Cash and cash equivalents at end of period	5,939	16,409
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	160,426	162,091
Cash payments (refunds) for income taxes	3,058	0
Accounts payable for capital expenditures eliminated from cash flows	$ 87,456	$ 58,278

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Summary of Consolidation Policy

9 Months Ended

Sep. 30, 2017

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, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and 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 September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger).  As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings.  The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger.  ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.  

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any 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 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. The Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Washington 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.

For Puget Energy, $86.4 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 $76.3 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

9 Months Ended

Sep. 30, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements

New Accounting Pronouncements

Revenue Recognition

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

In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date", deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to early adopt ASU 2014-09 using the original effective date.

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

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.

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. The Company is considering whether the new guidance will affect the accounting for purchase power agreements, easements and rights–of–way, utility pole attachments, and other utility industry–related arrangements.

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 will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows.

In November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash". The amendments 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 will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented and does not anticipate the new guidance will have a material impact on the consolidated statement of cash flows.

Definition of a Business

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

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

Retirement 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. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018. For the periods presented in the income statement, the Company’s non-service components for the nine months ended September 30, 2017, was a credit of $13.8 million for Puget Energy and $3.5 million for PSE.  The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

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Accounting for Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2017

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

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of September 30, 2017, the Company did not have any outstanding interest rate swap instruments.

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

Puget Energy and Puget Sound Energy
	At September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Volumes		Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Interest rate swap derivatives3	$	—	$	—	$	—	$450 million	$	—	$	141
Electric portfolio derivatives	*		11,656		39,622		*	36,460		41,329
Natural gas derivatives (MMBtus)4	305.3 million		7,826		25,776		336.4 million	26,619		19,101
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571
Current	**		$	16,605	$	49,820	**	$	54,341	$	44,310
Long-term	**		2,877		15,578		**	8,738		16,261
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571

_______________

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

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

³  Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017, and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

** Not meaningful and/or applicable.

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

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 September 30, 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	$	19,482	$	—	$	19,482	$	(12,961	)	$	—		$	6,521
Liabilities:
Energy derivative contracts	65,398		—		65,398		(12,961		)	(739		)	51,698

Puget Energy and Puget Sound Energy
	At December 31, 2016
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—	$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—		17,572
Interest rate swaps2	141		—		141		—			—		141

_______________

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

²  Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

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

Puget Energy and Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2017			2016			2017			2016
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	563		$	28		$	(651	)
	Interest expense	—			(349		)	—			(349		)
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	903			(8,873		)	(20,979		)	41,957
Realized	Electric generation fuel	(6,753		)	(3,194		)	(14,773		)	(36,204		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(880		)	2,546			(2,119		)	15,261
Realized	Purchased electricity	(4,356		)	(1,282		)	(14,434		)	(16,077		)
Total gain (loss) recognized in income on derivatives		$	(11,086	)	$	(10,589	)	$	(52,277	)	$	3,937

_______________

¹ Interest rate swap contracts are only 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 September 30, 2017, approximately 98.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated at least investment grade by rating agencies and 1.5% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of September 30, 2017, the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2017, PSE had cash posted as collateral of $1.4 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 during the nine months ended September 30, 2017 nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At September 30, 2017						At December 31, 2016
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	6,113	$	—	$	6,113	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	27,214		—		—		7,427		—		—
Forward value of contract3	739		1,384		—		507		—		—
Total	$	34,066	$	1,384	$	6,113	$	12,828	$	—	$	4,894

_______________

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

9 Months Ended

Sep. 30, 2017

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 $49.4 million and $49.1 million at September 30, 2017 and December 31, 2016, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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

Puget Energy		At September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,101,936		6,439,413		5,091,593		6,337,287
Long-term debt (variable-rate)	2	83,064		83,064		12,480		12,480
Total liabilities		$	5,435,000	$	6,768,709	$	5,354,073	$	6,560,028

Puget Sound Energy		At September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,229		4,465,126		3,497,298		4,360,783
Total liabilities		$	3,749,229	$	4,711,358	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016, 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 September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,106	$	4,550	$	11,656	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	3,794		4,032		7,826		23,316		3,303		26,619
Total assets	$	10,900	$	8,582	$	19,482	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	36,482		3,140		39,622		36,507		4,822		41,329
Natural gas derivative instruments	23,998		1,778		25,776		16,423		2,678		19,101
Total liabilities	$	60,480	$	4,918	$	65,398	$	53,071	$	7,500	$	60,571

_______________

¹  Interest rate derivative instruments are only held at Puget Energy, and matured January 2017.

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

Puget Energy and Puget Sound Energy	Three Months Ended September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	643		$	1,456		$	2,099		$	(3,062	)	$	(484	)	$	(3,546	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	2,458			—			2,458			574			—			574
Included in regulatory assets / liabilities	—			2,133			2,133			—			(212		)	(212		)
Settlements	(1,783		)	(1,301		)	(3,084		)	93			84			177
Transferred into Level 3	(1,668		)	—			(1,668		)	(727		)	—			(727		)
Transferred out of Level 3	1,760			(34		)	1,726			2,532			(331		)	2,201
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $0.9 million for the three months ended September 30, 2017 and 2016.

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

Puget Energy and Puget Sound Energy	Nine Months Ended September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	3,503			—			3,503			3,228			—			3,228
Included in regulatory assets / liabilities	—			5,715			5,715			—			2,869			2,869
Settlements	(5,622		)	(4,605		)	(10,227		)	(461		)	(1,731		)	(2,192		)
Transferred into Level 3	523			(553		)	(30		)	(2,807		)	—			(2,807		)
Transferred out of Level 3	2,034			1,072			3,106			6,795			302			7,097
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $1.9 millionand $4.0 million for the nine months ended September 30, 2017 and 2016, respectively.

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

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,550	$	3,140	Discounted cash flow	Power prices (per MWh)	$	8.54	$	28.98	$	17.99
Natural gas	$	4,032	$	1,778	Discounted cash flow	Natural gas prices (per MMBtu)	$	0.38	$	3.09	$	2.75

_______________

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2016:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	5,794	$	4,822	Discounted cash flow	Power prices (per MWh)	$	11.86	$	33.52	$	27.61
Natural gas	$	3,303	$	2,678	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.00	$	3.24	$	2.42

_______________

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 September 30, 2017 and December 31, 2016, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.7 million and $0.2 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 September 30, 2017, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 3.5% from June 30, 2017, causing an impairment of $1.0 million. As of March 31, 2017, due to significant decreases in forward power prices of 14.1% for years 2017-2022, and 24.4% for years 2023-2035 from December 31, 2016, impairments totaling $80.3 million were recorded to the Company's intangible asset contracts.

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

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	$	14,879	$	13,067	$	1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total year-to-date impairments						$	81,345

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
September 30, 2017
Wells Hydro	Power prices (per MWh)	$14.06	$26.86	$22.24
	Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017
Wells Hydro	Power prices (per MWh)	$8.76	$26.70	$20.86
	Power contract costs per quarter (in thousands)	3,965	4,223	4,051
Rocky Reach	Power prices (per MWh)	$8.53	$48.21	$27.69
	Power contract costs per quarter (in thousands)	5,827	6,780	6,150
Priest Rapids RP	Power prices (per MWh)	$13.70	$29.38	$23.14
	Power contract costs per year (in thousands)	620	4,022	2,306

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Retirement Benefits

9 Months Ended

Sep. 30, 2017

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, all non-represented and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees, along with International Brotherhood of Electrical Workers (IBEW) represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees.

In addition to providing pension benefits, PSE provides access to group medical care coverage and legacy life insurance benefits (Other Benefits) for certain retired employees.  These benefits are provided principally through an insurance company.  The group medical insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year.

Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,945		)	(11,589		)	—		—		(115		)	(112		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—
Amortization of net loss (gain)	—			—			269		228		(101		)	(233		)
Net periodic benefit cost	$	(327	)	$	(44	)	$	1,079	$	1,091	$	(73	)	$	(236	)

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,837		)	(34,964		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,485		)	(1,485		)	33		32		—			—
Amortization of net loss (gain)	—			—			807		683		(302		)	(289		)
Net periodic benefit cost	$	(983	)	$	(748	)	$	3,239	$	3,273	$	(219	)	$	(154	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,965		)	(11,638		)	—		—		(115		)	(112		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,262			3,963			392		333		(160		)	(295		)
Net periodic benefit cost	$	3,017		$	3,972		$	1,202	$	1,196	$	(132	)	$	(298	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,896		)	(35,110		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,180		)	(1,180		)	33		33		—			—
Amortization of net loss (gain)	9,786			11,443			1,175		997		(480		)	(474		)
Net periodic benefit cost	$	9,049		$	10,854		$	3,607	$	3,588	$	(397	)	$	(339	)

The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2017 and December 31, 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Nine Months Ended			Year Ended			Nine Months Ended			Year Ended			Nine Months Ended			Year Ended
(Dollars in Thousands)	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	15,060			18,913			685			1,085			54			93
Interest cost	21,279			28,689			1,714			2,325			375			533
Actuarial loss (gain)	(253		)	1,545			—			106			373			(2,262		)
Benefits paid	(31,344		)	(38,730		)	(1,428		)	(3,061		)	(857		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative Expense	—			(898		)	—			—			—			—
Benefit obligation at end of period	$	657,349		$	652,607		$	52,705		$	51,734		$	11,239		$	11,194

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, 2017 are expected to be at least $18.0 million, $1.9 million and $0.3 million, respectively. During the three months ended September 30, 2017, the Company made no contributions to fund the qualified pension plan, as the aggregate funding for the year has already been reached for the year ending December 31, 2017. During the three months ended September 30, 2017, the Company contributed $0.5 million and $0.1 million to fund the SERP and other postretirement plan, respectively. During the nine months ended September 30, 2017, the Company contributed $18.0 million, $1.4 million and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.

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Regulation and Rates

9 Months Ended

Sep. 30, 2017

Regulation and Rates [Abstract]

Regulation and Rates

Regulation and Rates

2013 Expedited Rate Filing, Decoupling and Centralia Decision

On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the expedited rate filing (ERF) and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No.7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital to 7.77% which updated long-term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the K-Factor (rate plan) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next general rate case (GRC) which was filed January 13, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.

General Rate Case Filing

On January 13, 2017, PSE filed its GRC with the Washington Commission which proposed a weighted cost of capital of 7.74%, or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8%. The requested combined electric tariff changes were a net increase of $86.3 million, or 4.1%, annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million, or 2.4%, annually. The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million, or 3.2%, annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million, or 3.2%, annually.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by the Washington Commission, would resolve all but four of the contested issues between the settling parties. 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 recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above.

Under the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing party in PSE’s pending GRC is advocating that PSE's decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE's existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms. PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. PSE's decoupling mechanism over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.

The Washington Commission approved the following PSE requests to change rates 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, 2017	2.0%	$41.9
May 1, 2016	1.0	20.8
Natural Gas:
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 $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.

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

Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)
Natural Gas:
2016	$47.4
2015	28.7

Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  

Electric Regulation and Rates

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for a system average interruption duration index. For the nine months ended September 30, 2017 and 2016, PSE incurred $21.1 million and $15.6 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred to a regulatory asset in 2017 and $6.5 million in 2016.

Power Cost Adjustment Mechanism

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

The graduated scale that was applicable through December 31, 2016 was as follows:

Annual Power Cost Variability	Company’s Share	Customers' Share
+/- $20 million	100%	—%
+/- $20 million - $40 million	50	50
+/- $40 million - $120 million	10	90
+/- $120 + million	5	95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and applies the following graduated scale:

	Company's Share		Customers' Share
Annual Power Cost 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

The settlement also resulted in the following changes to the PCA mechanism:

• Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;

• Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, other production and other power related expenses and O&M costs;

• Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC);

• Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and

• Establishment of a five-year moratorium on changes to the PCA.

For the nine months ended September 30, 2017, PSE under recovered its power costs by $8.9 million of which no amount was apportioned to customers.  This compares to an over recovery of power costs of $1.4 million for the nine months ended September 30, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included.  The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate.  The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.

Electric Conservation Rider

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

The following table sets forth conservation rider rate adjustments approved by the Washington Commission 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	0.7%	$16.5
May 1, 2016	(0.5)	(11.7)

Electric Property Tax Tracker Mechanism

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

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

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

Federal Incentive Tracker Tariff

The federal incentive tracker tariff passes through to customers the benefits associated with realized treasury grants and production tax credits. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.

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

Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2018, proposed	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 will be receiving from the Bonneville Power Administration (BPA) between October 1, 2017 and September 30, 2019.  Rates change bi-annually on October 1.

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
October 1, 2017	(0.6)%	$(80.8)
October 1, 2015	2.4	(76.4)

Power Cost Update Compliance Filing

The power cost update compliance filing is an update to a limited-scope proceeding to periodically reset power cost rates.  In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service.  To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission’s Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC.

The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2016	(1.7)%	$(37.3)

Natural Gas Regulation and Rates

Natural Gas Conservation Rider

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2017	(0.1)%	$(1.0)
May 1, 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 removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes.

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

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

Natural Gas Cost Recovery Mechanism

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

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2017	0.5%	$4.9
November 1, 2016	0.6	5.6

Purchased Gas Adjustment

PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.

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

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

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligations

The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, and natural gas mains where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO).

On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments.

The CCR rule and two new agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations. The changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO.

On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional costs, such as, monitoring, water treatment, forced evaporation and post-closure care for all Colstrip Units. As a result, in 2016 the Company increased the Colstrip ARO ending liability by $45.7 million for Colstrip Units 1 and 2 and $37.0 million for Colstrip Units 3 and 4.

The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. The Company will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.

For the nine months ended September 30, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $1.5 million for PSE and $1.4 million for Puget LNG in September 2017.

The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Changes in ARO
Balance at December 31, 2016	$	200,345
New asset retirement obligation recognized in the period1	2,881
Liability adjustments	(1,035		)
Revisions in estimated cash flows	(18,462		)
Accretion expense	4,126
Balance at September 30, 2017	$	187,855

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^{1  New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.}

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(8) Commitment and Contingencies

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. 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) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. Due to a re-estimate of Colstrip Units 1 and 2 ARO costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time.

Greenwood

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

Other Commitments and Contingencies

The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company recorded reserves of $0.6 million and $0.7 million relating to these claims as of September 30, 2017 and December 31, 2016, respectively.

In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2016, during the nine months ended September 30, 2017, the Company entered into new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.

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Summary of Consolidation Policy (Policies)

9 Months Ended

Sep. 30, 2017

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, named Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and 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 September 30, 2017, Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility.

In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger).  As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings.  The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger.  ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date.  

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any 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 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. The Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Washington 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.

For Puget Energy, $86.4 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 $76.3 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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Accounting for Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2017

Derivative [Line Items]

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

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

Puget Energy and Puget Sound Energy
	At September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Volumes		Assets1		Liabilities2		Volumes	Assets1		Liabilities2
Interest rate swap derivatives3	$	—	$	—	$	—	$450 million	$	—	$	141
Electric portfolio derivatives	*		11,656		39,622		*	36,460		41,329
Natural gas derivatives (MMBtus)4	305.3 million		7,826		25,776		336.4 million	26,619		19,101
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571
Current	**		$	16,605	$	49,820	**	$	54,341	$	44,310
Long-term	**		2,877		15,578		**	8,738		16,261
Total derivative contracts	**		$	19,482	$	65,398	**	$	63,079	$	60,571

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

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

³  Interest rate swap contracts are only held at Puget Energy, and matured January 2017.

⁴  All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

^*  Electric portfolio derivatives consist of electric generation fuel of 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017, and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

** Not meaningful and/or applicable.

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 September 30, 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	$	19,482	$	—	$	19,482	$	(12,961	)	$	—		$	6,521
Liabilities:
Energy derivative contracts	65,398		—		65,398		(12,961		)	(739		)	51,698

Puget Energy and Puget Sound Energy
	At December 31, 2016
	Gross Amount Recognized in the Statement of Financial Position1		Gross Amounts Offset in the Statement of Financial Position		Net of Amounts Presented in the Statement of Financial Position		Gross Amounts Not Offset in the Statement of Financial Position
(Dollars in Thousands)							Commodity Contracts			Cash Collateral Received/Posted		Net Amount
Assets:
Energy derivative contracts	$	63,079	$	—	$	63,079	$	(42,858	)	$	—	$	20,221
Liabilities:
Energy derivative contracts	60,430		—		60,430		(42,858		)	—		17,572
Interest rate swaps2	141		—		141		—			—		141

_______________

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

²  Interest rate swap contracts are only held at Puget Energy

Schedule of Credit Risk Related Contingent Features

The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At September 30, 2017						At December 31, 2016
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	6,113	$	—	$	6,113	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	27,214		—		—		7,427		—		—
Forward value of contract3	739		1,384		—		507		—		—
Total	$	34,066	$	1,384	$	6,113	$	12,828	$	—	$	4,894

_______________

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 locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income:

Puget Energy and Puget Sound Energy		Three Months Ended September 30,						Nine Months Ended September 30,
(Dollars in Thousands)	Location	2017			2016			2017			2016
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	563		$	28		$	(651	)
	Interest expense	—			(349		)	—			(349		)
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	903			(8,873		)	(20,979		)	41,957
Realized	Electric generation fuel	(6,753		)	(3,194		)	(14,773		)	(36,204		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(880		)	2,546			(2,119		)	15,261
Realized	Purchased electricity	(4,356		)	(1,282		)	(14,434		)	(16,077		)
Total gain (loss) recognized in income on derivatives		$	(11,086	)	$	(10,589	)	$	(52,277	)	$	3,937

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

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

Schedule of Impaired Intangible Assets

impairments totaling $80.3 million were recorded to the Company's intangible asset contracts.

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

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017	Wells Hydro	$	10,621	$	9,609	$	1,012
March 31, 2017	Wells Hydro	$	14,879	$	13,067	$	1,812
	Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008
Total year-to-date impairments						$	81,345

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 September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,101,936		6,439,413		5,091,593		6,337,287
Long-term debt (variable-rate)	2	83,064		83,064		12,480		12,480
Total liabilities		$	5,435,000	$	6,768,709	$	5,354,073	$	6,560,028

Puget Sound Energy		At September 30, 2017				At December 31, 2016
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities:
Junior subordinated notes	2	$	250,000	$	246,232	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,499,229		4,465,126		3,497,298		4,360,783
Total liabilities		$	3,749,229	$	4,711,358	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016, 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 September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	643		$	1,456		$	2,099		$	(3,062	)	$	(484	)	$	(3,546	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	2,458			—			2,458			574			—			574
Included in regulatory assets / liabilities	—			2,133			2,133			—			(212		)	(212		)
Settlements	(1,783		)	(1,301		)	(3,084		)	93			84			177
Transferred into Level 3	(1,668		)	—			(1,668		)	(727		)	—			(727		)
Transferred out of Level 3	1,760			(34		)	1,726			2,532			(331		)	2,201
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $0.9 million for the three months ended September 30, 2017 and 2016.

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

Puget Energy and Puget Sound Energy	Nine Months Ended September 30,
(Dollars in Thousands)	2017									2016
Level 3 Roll-Forward Net Asset/(Liability)	Electric			Natural Gas			Total			Electric			Natural Gas			Total
Balance at beginning of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	3,503			—			3,503			3,228			—			3,228
Included in regulatory assets / liabilities	—			5,715			5,715			—			2,869			2,869
Settlements	(5,622		)	(4,605		)	(10,227		)	(461		)	(1,731		)	(2,192		)
Transferred into Level 3	523			(553		)	(30		)	(2,807		)	—			(2,807		)
Transferred out of Level 3	2,034			1,072			3,106			6,795			302			7,097
Balance at end of period	$	1,410		$	2,254		$	3,664		$	(590	)	$	(943	)	$	(1,533	)

______________

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 $1.9 millionand $4.0 million for the nine months ended September 30, 2017 and 2016, 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 September 30, 2017:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,550	$	3,140	Discounted cash flow	Power prices (per MWh)	$	8.54	$	28.98	$	17.99
Natural gas	$	4,032	$	1,778	Discounted cash flow	Natural gas prices (per MMBtu)	$	0.38	$	3.09	$	2.75

_______________

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

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2016:

Puget Energy and Puget Sound Energy	Fair Value						Range
(Dollars in Thousands)	Assets1		Liabilities1		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	5,794	$	4,822	Discounted cash flow	Power prices (per MWh)	$	11.86	$	33.52	$	27.61
Natural gas	$	3,303	$	2,678	Discounted cash flow	Natural gas prices (per MMBtu)	$	2.00	$	3.24	$	2.42

_______________

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
September 30, 2017
Wells Hydro	Power prices (per MWh)	$14.06	$26.86	$22.24
	Power contract costs per quarter (in thousands)	4,126	4,126	4,126
March 31, 2017
Wells Hydro	Power prices (per MWh)	$8.76	$26.70	$20.86
	Power contract costs per quarter (in thousands)	3,965	4,223	4,051
Rocky Reach	Power prices (per MWh)	$8.53	$48.21	$27.69
	Power contract costs per quarter (in thousands)	5,827	6,780	6,150
Priest Rapids RP	Power prices (per MWh)	$13.70	$29.38	$23.14
	Power contract costs per year (in thousands)	620	4,022	2,306

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 September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,106	$	4,550	$	11,656	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	3,794		4,032		7,826		23,316		3,303		26,619
Total assets	$	10,900	$	8,582	$	19,482	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	36,482		3,140		39,622		36,507		4,822		41,329
Natural gas derivative instruments	23,998		1,778		25,776		16,423		2,678		19,101
Total liabilities	$	60,480	$	4,918	$	65,398	$	53,071	$	7,500	$	60,571

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2017

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 September 30, 2017 and December 31, 2016:

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Nine Months Ended			Year Ended			Nine Months Ended			Year Ended			Nine Months Ended			Year Ended
(Dollars in Thousands)	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Change in benefit obligation:
Benefit obligation at beginning of period	$	652,607		$	643,088		$	51,734		$	51,279		$	11,194		$	13,946
Service cost	15,060			18,913			685			1,085			54			93
Interest cost	21,279			28,689			1,714			2,325			375			533
Actuarial loss (gain)	(253		)	1,545			—			106			373			(2,262		)
Benefits paid	(31,344		)	(38,730		)	(1,428		)	(3,061		)	(857		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative Expense	—			(898		)	—			—			—			—
Benefit obligation at end of period	$	657,349		$	652,607		$	52,705		$	51,734		$	11,239		$	11,194

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 nine months ended September 30, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,945		)	(11,589		)	—		—		(115		)	(112		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—
Amortization of net loss (gain)	—			—			269		228		(101		)	(233		)
Net periodic benefit cost	$	(327	)	$	(44	)	$	1,079	$	1,091	$	(73	)	$	(236	)

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,837		)	(34,964		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,485		)	(1,485		)	33		32		—			—
Amortization of net loss (gain)	—			—			807		683		(302		)	(289		)
Net periodic benefit cost	$	(983	)	$	(748	)	$	3,239	$	3,273	$	(219	)	$	(154	)

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 September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,093			7,064			571		581		125			88
Expected return on plan assets	(11,965		)	(11,638		)	—		—		(115		)	(112		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,262			3,963			392		333		(160		)	(295		)
Net periodic benefit cost	$	3,017		$	3,972		$	1,202	$	1,196	$	(132	)	$	(298	)

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	15,060		$	14,185		$	685	$	814	$	54		$	70
Interest cost	21,279			21,516			1,714		1,744		375			399
Expected return on plan assets	(35,896		)	(35,110		)	—		—		(346		)	(334		)
Amortization of prior service cost	(1,180		)	(1,180		)	33		33		—			—
Amortization of net loss (gain)	9,786			11,443			1,175		997		(480		)	(474		)
Net periodic benefit cost	$	9,049		$	10,854		$	3,607	$	3,588	$	(397	)	$	(339	)

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Regulation and Rates Public Utilities, Regulatory Proceeding (Tables) - Subsidiaries [Member]

9 Months Ended

Sep. 30, 2017

Decoupling Mechanism [Member]

Regulation and Rates [Line Items]

Schedule of Deferrals Not Included in Rate Increases

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

Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)
Natural Gas:
2016	$47.4
2015	28.7

Schedule of Graduated Scale of Rate Adjustment Mechanisms

The Washington Commission approved the following PSE requests to change rates 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, 2017	2.0%	$41.9
May 1, 2016	1.0	20.8
Natural Gas:
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 $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.

PCA Mechanism [Member] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and applies the following graduated scale:

	Company's Share		Customers' Share
Annual Power Cost 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

The graduated scale that was applicable through December 31, 2016 was as follows:

Annual Power Cost Variability	Company’s Share	Customers' Share
+/- $20 million	100%	—%
+/- $20 million - $40 million	50	50
+/- $40 million - $120 million	10	90
+/- $120 + million	5	95

Property tax tracker [Member] [Domain] | Natural Gas [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

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

Property tax tracker [Member] [Domain] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

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

Conservation Rider [Member] | Natural Gas [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

Conservation Rider [Member] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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	0.7%	$16.5
May 1, 2016	(0.5)	(11.7)

Treasury Grants [Member] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2018, proposed	0.2%	$(48.2)
January 1, 2017	0.3	(51.7)
January 1, 2016	(0.2)	(57.3)

Residential Exchange Benefit [Member] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
October 1, 2017	(0.6)%	$(80.8)
October 1, 2015	2.4	(76.4)

Power Cost Only Rate Case (PCORC) [Member] | Electric [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date:

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2016	(1.7)%	$(37.3)

Cost recovery mechanism [Member] | Natural Gas [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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

Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2017	0.5%	$4.9
November 1, 2016	0.6	5.6

Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]

Regulation and Rates [Line Items]

Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments

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)

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Changes in ARO
Balance at December 31, 2016	$	200,345
New asset retirement obligation recognized in the period1	2,881
Liability adjustments	(1,035		)
Revisions in estimated cash flows	(18,462		)
Accretion expense	4,126
Balance at September 30, 2017	$	187,855

_______________

^{1  New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.}

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Summary of Consolidation Policy (Details) $ in Millions	Sep. 30, 2017 USD ($) mi²
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Construction in Progress, Gross	$ 76.3
Puget LNG [Member]
Summary of Consolidation Policy
Construction in Progress and O&M Expenses	$ 86.5
Jointly Owned Non-Utility Plant Share	57.00%
Construction in Progress, Gross	$ 86.4

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New Accounting Pronouncements Retirement Benefits ASU (Details) - Pension Plan [Member] $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 13.8
Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 3.5

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) MWh MMBTU	Dec. 31, 2016 USD ($) MWh MMBTU
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	$ 0	$ 450
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	305.3	336.4
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	165.0	186.8
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh	2.6	3.6
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years

XML

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Unrealized gain on derivative instruments	$ 16,605	$ 54,341
Derivative Liability, Current	49,820	44,310
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	16,605	54,341
Derivative Liability, Current	49,820	44,170
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Commodity Contract [Member]
Derivative [Line Items]
Assets	19,482	63,079
Derivative Liability	65,398	60,430
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	19,482	63,079
Derivative Liability	65,398	60,571
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	16,605	54,341
Derivative Liability, Current	49,820	44,310
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	0	450,000
Assets	0	0
Derivative Liability	0	141
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	11,656	36,460
Derivative Liability	39,622	41,329
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	7,826	26,619
Derivative Liability	$ 25,776	$ 19,101

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		Sep. 30, 2017 USD ($) MMBTU	Dec. 31, 2016 USD ($) MMBTU
Liabilities:
Derivative Asset, Current		$ 16,605	$ 54,341
Derivative Liability, Current		49,820	44,310
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		15,578	16,261
Commodity Contract [Member]
Assets:
Gross Amount Recognized in the Statement of Financial Position	[1]	19,482	63,079
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		19,482	63,079
Commodity Contracts		(12,961)	(42,858)
Cash Collateral Received		0	0
Net Amount		6,521	20,221
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1]	65,398	60,430
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		65,398	60,430
Commodity Contracts		(12,961)	(42,858)
Cash Collateral Posted		(739)	0
Net Amount		51,698	17,572
Interest Rate Contract [Member]
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1],[2]		141
Gross Amounts Offset in the Statement of Financial Position	[2]		0
Net of Amounts Presented in the Statement of Financial Position			141
Commodity Contracts	[2]		0
Cash Collateral Posted	[2]		0
Net Amount			141
Subsidiaries [Member]
Liabilities:
Derivative Asset, Current		16,605	54,341
Derivative Liability, Current		49,820	44,170
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		15,578	16,261
Not Designated as Hedging Instrument [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		19,482	63,079
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		65,398	60,571
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		0	450,000
Assets:
Net of Amounts Presented in the Statement of Financial Position		0	0
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		0	141
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		11,656	36,460
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		$ 39,622	$ 41,329
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Liabilities:
Derivative, Nonmonetary Notional Amount | MMBTU		305.3	336.4
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		$ 7,826	$ 26,619
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		25,776	19,101
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Liabilities:
Derivative Asset, Current		16,605	54,341
Derivative Liability, Current		49,820	44,310
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		$ 15,578	$ 16,261

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

[2] 2 Interest rate swap contracts are only held at Puget Energy

XML

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (23)	$ 6,327	$ 23,098	$ (57,218)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(23)	6,327	23,098	(57,218)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	11,086	10,589	52,277	(3,937)
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	(563)	(28)	651
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	349	0	349
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	(903)	8,873	20,979	(41,957)
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	6,753	3,194	14,773	36,204
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	4,356	1,282	14,434	16,077
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	$ 880	$ (2,546)	$ 2,119	$ (15,261)

XML

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		98.50%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		1.50%
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 34,066	$ 12,828
Posted Collateral		1,384	0
Additional Collateral, Aggregate Fair Value		6,113	4,894
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	1,400
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	6,113	4,894
Posted Collateral	[2]	0	0
Additional Collateral, Aggregate Fair Value	[2]	6,113	4,894
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]	27,214	7,427
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]	739	507
Posted Collateral	[3]	1,384	0
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		Sep. 30, 2017	Dec. 31, 2016
Liabilities:
Total long-term debt		$ 5,235,000	$ 5,351,661
Subsidiaries [Member]
Liabilities:
Total long-term debt		3,549,229	3,744,886
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		3,749,229	3,747,298
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		250,000	250,000
Long-term debt (fixed-rate), net of discount	[1]	3,499,229	3,497,298
Debt issuance costs	[1]	25,300	27,200
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		4,711,358	4,571,044
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		246,232	210,261
Long-term debt (fixed-rate), net of discount	[1]	$ 4,465,126	$ 4,360,783

[1] 1 The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

XML

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 2,099	$ (3,546)	$ 1,597	$ (9,728)
Included in earnings	[1]	2,458	574	3,503	3,228
Included in regulatory assets/liabilities		2,133	(212)	5,715	2,869
Settlements		(3,084)	177	(10,227)	(2,192)
Transferred into Level 3		(1,668)	(727)	(30)	(2,807)
Transferred out of Level 3		1,726	2,201	3,106	7,097
Balance at end of period		3,664	(1,533)	3,664	(1,533)
Long-term Debt, Excluding Current Maturities		5,235,000		5,235,000		$ 5,351,661
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability						141
Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		900	900	1,900	4,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		643	(3,062)	972	(7,345)
Included in earnings	[1]	2,458	574	3,503	3,228
Included in regulatory assets/liabilities		0	0	0	0
Settlements		(1,783)	93	(5,622)	(461)
Transferred into Level 3		(1,668)	(727)	523	(2,807)
Transferred out of Level 3		1,760	2,532	2,034	6,795
Balance at end of period		1,410	(590)	1,410	(590)
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,456	(484)	625	(2,383)
Included in earnings	[1]	0	0	0	0
Included in regulatory assets/liabilities		2,133	(212)	5,715	2,869
Settlements		(1,301)	84	(4,605)	(1,731)
Transferred into Level 3		0	0	(553)	0
Transferred out of Level 3		(34)	(331)	1,072	302
Balance at end of period		2,254	$ (943)	2,254	$ (943)
Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		3,549,229		3,549,229		3,744,886
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		19,482		19,482		63,079
Derivative Liability		65,398		65,398		60,571
Fair Value, Measurements, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		11,656		11,656		36,460
Derivative Liability		39,622		39,622		41,329
Fair Value, Measurements, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,826		7,826		26,619
Derivative Liability		25,776		25,776		19,101
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		10,900		10,900		53,982
Derivative Liability		60,480		60,480		53,071
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		7,106		7,106		30,666
Derivative Liability		36,482		36,482		36,507
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		3,794		3,794		23,316
Derivative Liability		23,998		23,998		16,423
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		8,582		8,582		9,097
Derivative Liability		4,918		4,918		7,500
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		4,550		4,550		5,794	[2]
Derivative Liability		3,140		3,140		4,822	[2]
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		4,032		4,032		3,303	[2]
Derivative Liability		1,778		1,778		2,678	[2]
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		141
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		141
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		49,400		49,400		49,100
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		5,435,000		5,435,000		5,354,073
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]
Unamortized Debt Issuance Expense	[3]	29,100		29,100		33,000
Subordinated Debt Obligations, Fair Value Disclosure		250,000		250,000		250,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	5,101,936		5,101,936		5,091,593
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	83,064		83,064		12,480
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		3,749,229		3,749,229		3,747,298
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]
Unamortized Debt Issuance Expense	[3]	25,300		25,300		27,200
Subordinated Debt Obligations, Fair Value Disclosure		250,000		250,000		250,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	3,499,229		3,499,229		3,497,298
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		6,768,709		6,768,709		6,560,028
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		246,232		246,232		210,261
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	6,439,413		6,439,413		6,337,287
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	83,064		83,064		12,480
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		4,711,358		4,711,358		4,571,044
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		246,232		246,232		210,261
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	$ 4,465,126		$ 4,465,126		$ 4,360,783

[1] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjgwMjdlNTZkN2JjYTRmMDU5ODRiMjQxOTIzZDdkZDE4fFRleHRTZWxlY3Rpb246NDVEMjNBM0EyQ0VGRERCMEY1MjJGMTQ1MzRBMjI4ODQM}

[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 $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

XML

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2017 USD ($) $ / MWh	Mar. 31, 2017 USD ($) $ / MWh	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) $ / MMBTU $ / MWh	Sep. 30, 2016 USD ($)	Dec. 31, 2035	Dec. 31, 2034	Dec. 31, 2033	Dec. 31, 2032	Dec. 31, 2031	Dec. 31, 2030	Dec. 31, 2029	Dec. 31, 2028	Dec. 31, 2027	Dec. 31, 2026	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016 USD ($) $ / 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%			10.00%																				10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 1,700,000			$ 1,700,000																				$ 200,000
Finite-Lived Intangible Assets, Net
Impairment of Intangible Assets (Excluding Goodwill)		$ 80,300,000		81,345,000
Fair Value Inputs, Comparability Adjustments	3.50%	14.10%
Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	19,482,000			19,482,000																				63,079,000
Derivative Liability	65,398,000			65,398,000																				$ 60,571,000
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	900,000		$ 900,000	$ 1,900,000	$ 4,000,000
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				8.54																				11.86
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				28.98																				33.52
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				17.99																				27.61
Electric Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	11,656,000			$ 11,656,000																				$ 36,460,000
Derivative Liability	39,622,000			$ 39,622,000																				$ 41,329,000
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				0.38																				2.00
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU				3.09																				3.24
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				2.75																				2.42
Natural Gas Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	7,826,000			$ 7,826,000																				$ 26,619,000
Derivative Liability	25,776,000			25,776,000																				19,101,000
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	19,482,000			19,482,000																				63,079,000
Derivative Liability	65,398,000			65,398,000																				$ 60,430,000
Wells Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	10,621,000	$ 14,879,000		10,621,000
Impairment of Intangible Assets (Excluding Goodwill)	1,012,000	1,812,000
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	$ 9,609,000	$ 13,067,000		$ 9,609,000
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	14.06	8.76
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 3,965
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	26.86	26.70
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 4,223
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	22.24	20.86
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 4,051
Rocky Reach Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		235,331,000
Impairment of Intangible Assets (Excluding Goodwill)		75,513,000
Rocky Reach Project [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 159,818,000
Rocky Reach Project [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		8.53
Fair Value Inputs, Power Contract Costs		$ 5,827
Rocky Reach Project [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		48.21
Fair Value Inputs, Power Contract Costs		$ 6,780
Rocky Reach 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		27.69
Fair Value Inputs, Power Contract Costs		$ 6,150
Priest Rapids Development [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		5,665,000
Impairment of Intangible Assets (Excluding Goodwill)		3,008,000
Priest Rapids Development [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 2,657,000
Priest Rapids Development [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		13.70
Fair Value Inputs, Power Contract Costs		$ 620
Priest Rapids Development [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		29.38
Fair Value Inputs, Power Contract Costs		$ 4,022
Priest Rapids Development [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		23.14
Fair Value Inputs, Power Contract Costs		$ 2,306
Scenario, Forecast [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Comparability Adjustments						24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	14.10%	14.10%	14.10%	14.10%	14.10%

XML

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Qualified Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer			$ 18,000
Components of net periodic benefit cost:
Service cost			15,060		$ 18,913
Interest cost			21,279		28,689
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 500		1,400
Components of net periodic benefit cost:
Service cost			685		1,085
Interest cost			1,714		2,325
Other Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	100		200
Components of net periodic benefit cost:
Service cost			54		93
Interest cost			375		$ 533
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,020	$ 4,976	15,060	$ 14,185
Interest cost	7,093	7,064	21,279	21,516
Expected return on plan assets	(11,945)	(11,589)	(35,837)	(34,964)
Amortization of prior service cost	(495)	(495)	(1,485)	(1,485)
Amortization of net loss (gain)	0	0	0	0
Net periodic benefit cost	(327)	(44)	(983)	(748)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	228	271	685	814
Interest cost	571	581	1,714	1,744
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	33	32
Amortization of net loss (gain)	269	228	807	683
Net periodic benefit cost	1,079	1,091	3,239	3,273
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	18	21	54	70
Interest cost	125	88	375	399
Expected return on plan assets	(115)	(112)	(346)	(334)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(101)	(233)	(302)	(289)
Net periodic benefit cost	(73)	(236)	(219)	(154)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,020	4,976	15,060	14,185
Interest cost	7,093	7,064	21,279	21,516
Expected return on plan assets	(11,965)	(11,638)	(35,896)	(35,110)
Amortization of prior service cost	(393)	(393)	(1,180)	(1,180)
Amortization of net loss (gain)	3,262	3,963	9,786	11,443
Net periodic benefit cost	3,017	3,972	9,049	10,854
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	228	271	685	814
Interest cost	571	581	1,714	1,744
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	33	33
Amortization of net loss (gain)	392	333	1,175	997
Net periodic benefit cost	1,202	1,196	3,607	3,588
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	18	21	54	70
Interest cost	125	88	375	399
Expected return on plan assets	(115)	(112)	(346)	(334)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(160)	(295)	(480)	(474)
Net periodic benefit cost	$ (132)	$ (298)	$ (397)	$ (339)

XML

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 652,607	$ 643,088
Service cost	15,060	18,913
Interest cost	21,279	28,689
Actuarial loss/(gain)	(253)	1,545
Benefits paid	(31,344)	(38,730)
Medicare part D subsidiary received	0	0
Administrative Expense	0	(898)
Benefit obligation at end of period	657,349	652,607
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	51,734	51,279
Service cost	685	1,085
Interest cost	1,714	2,325
Actuarial loss/(gain)	0	106
Benefits paid	(1,428)	(3,061)
Medicare part D subsidiary received	0	0
Administrative Expense	0	0
Benefit obligation at end of period	52,705	51,734
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	11,194	13,946
Service cost	54	93
Interest cost	375	533
Actuarial loss/(gain)	373	(2,262)
Benefits paid	(857)	(1,264)
Medicare part D subsidiary received	100	148
Administrative Expense	0	0
Benefit obligation at end of period	$ 11,239	$ 11,194

XML

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2017
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		$ 18.0
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	$ 0.5	1.4
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.1	$ 0.2
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			1.9
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

XML

Regulation and Rates (Details) - Subsidiaries [Member] $ in Millions															9 Months Ended		12 Months Ended
	Jan. 01, 2018 USD ($)	Nov. 01, 2017 USD ($)	Oct. 01, 2017 USD ($)	Sep. 15, 2017 USD ($)	May 01, 2017 USD ($)	Apr. 03, 2017 USD ($)	Jan. 13, 2017 USD ($)	Jan. 01, 2017 USD ($)	Dec. 01, 2016 USD ($)	Nov. 01, 2016 USD ($)	May 01, 2016 USD ($)	Jan. 01, 2016 USD ($)	Oct. 01, 2015 USD ($)	Jun. 25, 2013	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 30, 2013
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities														7.77%
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure														48.00%
Public Utilities, Rate Case, Approved Effective Return on Equity														9.80%
Electric [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period															$ 21.1	$ 15.6
Storm Damage Costs Deferred During Period															12.4	6.5
Public Utilities, Rate Case, Deferred Storm Costs Threshold															8.0
Residential Exchange Benefit [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage													2.40%
Public Utilities, Approved credit to be passed back to eligible customers													$ (76.4)
Federal Incentive Tracker Tariff [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage								0.30%				(0.20%)
Public Utilities, Approved credit to be passed back to eligible customers								$ (51.7)				$ (57.3)
Power Cost Only Rate Case (PCORC) [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage									(1.70%)
Public Utilities, Approved Rate Increase (Decrease), Amount									$ (37.3)
Energy Conservation Costs [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					(0.10%)						0.30%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ (1.0)						$ 2.9
Energy Conservation Costs [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					0.70%						(0.50%)
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 16.5						$ (11.7)
Property tax tracker [Member] [Domain] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					(0.10%)						0.40%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ (1.1)						$ 3.5
Property tax tracker [Member] [Domain] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					(0.04%)						0.30%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ (0.9)						$ 5.7
Cost recovery mechanism [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage										0.60%
Public Utilities, Approved Rate Increase (Decrease), Amount										$ 5.6
Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage										(0.40%)
Public Utilities, Approved Rate Increase (Decrease), Amount										$ (4.1)
Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Public Utilities, Percentage of Earning to Be Shared Between the Company and Customers														50.00%
Decoupling Mechanism [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					2.40%						2.80%	2.20%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 22.4						$ 25.4						$ 2.2	$ 5.5
Decoupling Mechanism [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					2.00%						1.00%	3.00%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 41.9						$ 20.8						11.9	11.9
Decoupling Mechanism [Member] | Maximum [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage												3.00%
Decoupling Mechanism [Member] | Deferred Revenue [Domain] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount																	$ 47.4	$ 28.7
General Rate Case [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities				7.60%			7.74%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities				6.55%			6.69%
Public Utilities, Requested Equity Capital Structure, Percentage				48.50%			48.50%
Public Utilities, Requested Return on Equity, Percentage				9.50%			9.80%
Number of new mechanisms							2
Number of parties that agreed to settle				10
Number of parties total				11
Number of contested issues not settled				4
General Rate Case [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 22.3
Public Utilities, Requested Rate Increase (Decrease), Percentage							2.40%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 35.5		$ 29.3
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage				3.80%		3.20%
General Rate Case [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 86.3
Public Utilities, Requested Rate Increase (Decrease), Percentage							4.10%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount				$ 20.2		$ 67.9
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage				0.90%		3.20%
Customers share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			50.00%
Customers share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			90.00%
Customers share [Member] | Range 4 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			95.00%
Customers share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			0.00%
Company's share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			50.00%
Company's share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			10.00%
Company's share [Member] | Range 4 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			5.00%
Company's share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage																			100.00%
Under Recovery [Member] | Customers share [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount																0.0
Under Recovery [Member] | Customers share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								50.00%
Under Recovery [Member] | Customers share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								90.00%
Under Recovery [Member] | Customers share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								0.00%
Under Recovery [Member] | Company's share [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount															(8.9)	$ (1.4)
Under Recovery [Member] | Company's share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								50.00%
Under Recovery [Member] | Company's share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								10.00%
Under Recovery [Member] | Company's share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								100.00%
Over Recovery [Member] | Customers share [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount															$ 0.0
Over Recovery [Member] | Customers share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								65.00%
Over Recovery [Member] | Customers share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								90.00%
Over Recovery [Member] | Customers share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								0.00%
Over Recovery [Member] | Company's share [Member] | Range 2 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								35.00%
Over Recovery [Member] | Company's share [Member] | Range 3 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								10.00%
Over Recovery [Member] | Company's share [Member] | Range 1 [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage								100.00%
Deferral Trigger [Member] [Member] | Minimum [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount								$ 30.0
Deferral Trigger [Member] [Member] | Maximum [Member] | Electric [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount								$ 20.0
Scenario, Forecast [Member] | Federal Incentive Tracker Tariff [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage	0.20%
Public Utilities, Requested credit to be passed back to eligible customers	$ (48.2)
Subsequent Event [Member] | Residential Exchange Benefit [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage			(0.60%)
Public Utilities, Approved credit to be passed back to eligible customers			$ (80.8)
Subsequent Event [Member] | Cost recovery mechanism [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		0.50%
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 4.9
Subsequent Event [Member] | Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		(3.30%)
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (30.8)

XML

Asset Retirement Obligation (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 06, 2016
Commitments and Contingencies			2
Subsidiaries [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 200,345
New asset retirement obligation recognized in the period1	2,881
Liability adjustments	(1,035)
Revisions in estimated cash flows	(18,462)
Accretion expense	4,126
Closing balance	187,855
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Decommissioning Liability, Noncurrent	5,500	$ 45,700
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member]
Decommissioning Liability, Noncurrent	12,700	$ 37,000
Subsidiaries [Member] | Tacoma LNG [Member]
Decommissioning Liability, Noncurrent	1,500
Puget LNG [Member] | Tacoma LNG [Member]
Decommissioning Liability, Noncurrent	$ 1,400

XML

Commitments and Contingencies (Details) $ in Millions			3 Months Ended
	Jun. 19, 2017 USD ($)	Mar. 28, 2017 USD ($)	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 20, 2016 USD ($)
Loss Contingencies [Line Items]
Regulatory Assets				$ 175.0	$ 176.8
Estimated Litigation Liability							$ 3.2
Loss Contingency, Allegations	$ 1.3	$ 1.3
Loss Contingency, Accrual, Current						$ 3.2
Loss Contingency, Damages Awarded, Value	$ 2.8	$ 2.8
Loss Contingency Accrual, Payments			$ 1.5
Contractual Obligation				729.5
Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation claims accrual				$ 0.6	$ 0.7
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