UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 Six Months Ended June 30, 2017 and 2016	5
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2017 and 2016	6
	Consolidated Balance Sheets – June 30, 2017 and December 31, 2016	7
	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2017 and 2016	8
	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and Six Months Ended June 30, 2017 and 2016	9
	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2017 and 2016	10
	Consolidated Balance Sheets – June 30, 2017 and December 31, 2016	11
	Consolidated Statements of Cash Flows – Six Months Ended June 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	34
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	52
Item 4.	Controls and Procedures	53
Part II.	Other Information	54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	54
Signatures		55
Exhibit Index		56

2

DEFINITIONS

ARO	Asset Retirement and Environmental Obligations
ASU	Accounting Standards Update
ASC	Accounting Standards Codification
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
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
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
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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Operating revenue:
Electric	$	529,807		$	497,152		$	1,198,792		$	1,127,343
Natural gas	180,105			163,443			580,169			486,851
Other	9,855			7,574			18,038			16,672
Total operating revenue	719,767			668,169			1,796,999			1,630,866
Operating expenses:
Energy costs:
Purchased electricity	129,799			118,551			309,381			261,448
Electric generation fuel	34,163			40,930			85,473			95,123
Residential exchange	(15,121		)	(13,376		)	(38,568		)	(33,516		)
Purchased natural gas	63,183			48,273			215,984			171,376
Unrealized (gain) loss on derivative instruments, net	3,834			(46,724		)	23,121			(63,546		)
Utility operations and maintenance	145,555			138,018			297,618			284,008
Non-utility expense and other	6,144			5,179			11,339			10,814
Depreciation and amortization	119,457			111,273			234,710			218,787
Conservation amortization	25,691			22,540			60,453			55,751
Taxes other than income taxes	77,032			67,871			195,731			170,163
Total operating expenses	589,737			492,535			1,395,242			1,170,408
Operating income (loss)	130,030			175,634			401,757			460,458
Other income (expense):
Other income	6,263			7,078			12,223			13,053
Other expense	(2,042		)	(2,122		)	(3,257		)	(3,462		)
Non-hedged interest rate swap (expense) income	—			(359		)	28			(1,213		)
Interest charges:
AFUDC	2,555			2,603			4,730			4,962
Interest expense	(88,409		)	(88,676		)	(176,991		)	(177,489		)
Income (loss) before income taxes	48,397			94,158			238,490			296,309
Income tax (benefit) expense	13,122			29,605			75,665			90,570
Net income (loss)	$	35,275		$	64,553		$	162,825		$	205,739

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

5

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017		2016
Net income (loss)	$	35,275		$	64,553		$	162,825	$	205,739
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $(115), $(100), $359, and $(200), respectively	(214		)	(185		)	666		(371		)
Other comprehensive income (loss)	(214		)	(185		)	666		(371		)
Comprehensive income (loss)	$	35,061		$	64,368		$	163,491	$	205,368

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

6

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS
	June 30, 2017			December 31, 2016
Utility plant (at original cost, including construction work in progress of $505,334 and $420,278, respectively):
Electric plant	$	7,824,350		$	7,673,772
Natural gas plant	3,178,998			3,051,586
Common plant	673,542			594,994
Less: Accumulated depreciation and amortization	(2,321,677		)	(2,161,796		)
Net utility plant	9,355,213			9,158,556
Other property and investments:
Goodwill	1,656,513			1,656,513
Other property and investments	146,316			106,418
Total other property and investments	1,802,829			1,762,931
Current assets:
Cash and cash equivalents	7,805			28,878
Restricted cash	12,048			12,418
Accounts receivable, net of allowance for doubtful accounts of $9,977 and $9,798, respectively	251,304			329,375
Unbilled revenue	115,945			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	100,772			106,378
Fuel and natural gas inventory, at average cost	55,598			58,181
Unrealized gain on derivative instruments	16,078			54,341
Prepaid expense and other	29,146			43,046
Power contract acquisition adjustment gain	15,544			33,413
Total current assets	604,240			902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,598			72,038
Power cost adjustment mechanism	4,505			4,531
Regulatory assets related to power contracts	20,737			22,613
Other regulatory assets	1,004,297			1,034,348
Unrealized gain on derivative instruments	4,505			8,738
Power contract acquisition adjustment gain	168,040			241,648
Other	62,589			58,109
Total other long-term and regulatory assets	1,336,271			1,442,025
Total assets	$	13,098,553		$	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
	June 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	576,161			413,468
Accumulated other comprehensive income (loss), net of tax	(33,046		)	(33,712		)
Total common shareholder’s equity	3,852,072			3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,162,000			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Long-term debt	1,860,554			1,812,480
Debt discount, issuance costs and other	(227,766		)	(234,679		)
Total long-term debt	5,206,648			5,351,661
Total capitalization	9,058,720			9,040,374
Current liabilities:
Accounts payable	245,171			317,043
Short-term debt	5,000			245,763
Current maturities of long-term debt	202,412			2,412
Purchased gas adjustment payable	10,980			—
Accrued expenses:
Taxes	102,132			111,428
Salaries and wages	39,245			49,749
Interest	74,046			73,610
Unrealized loss on derivative instruments	44,031			44,310
Power contract acquisition adjustment loss	2,983			3,159
Other	87,756			71,996
Total current liabilities	813,756			919,470
Other long-term and regulatory liabilities:
Deferred income taxes	1,646,515			1,570,931
Unrealized loss on derivative instruments	18,237			16,261
Regulatory liabilities	620,950			654,622
Regulatory liabilities related to power contracts	183,583			275,061
Power contract acquisition adjustment loss	17,754			19,454
Other deferred credits	739,038			770,207
Total other long-term and regulatory liabilities	3,226,077			3,306,536
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	13,098,553		$	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)
	Six Months Ended June 30,
	2017			2016
Operating activities:
Net income (loss)	$	162,825		$	205,739
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	234,710			218,787
Conservation amortization	60,453			55,751
Deferred income taxes and tax credits, net	75,665			90,018
Net unrealized (gain) loss on derivative instruments	22,980			(65,414		)
AFUDC – equity	(6,766		)	(7,048		)
Funding of pension liability	(18,000		)	(9,000		)
Regulatory assets and liabilities	(44,731		)	(120,615		)
Other long-term assets and liabilities	11,194			14,519
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	196,179			184,595
Materials and supplies	5,606			(18,594		)
Fuel and natural gas inventory	2,473			4,974
Prepayments and other	13,900			(2,738		)
Purchased gas adjustment	13,765			(1,027		)
Accounts payable	(49,478		)	(64,132		)
Taxes payable	(9,296		)	(13,230		)
Other	(5,809		)	4,650
Net cash provided by (used in) operating activities	665,670			477,235
Investing activities:
Construction expenditures – excluding equity AFUDC	(496,652		)	(303,834		)
Restricted cash	370			(2,179		)
Other	(6,642		)	(4,851		)
Net cash provided by (used in) investing activities	(502,924		)	(310,864		)
Financing activities:
Change in short-term debt, net	(240,763		)	(123,004		)
Dividends paid	(132		)	(74,268		)
Proceeds from long-term debt and bonds issued	48,073			—
Other	9,003			7,426
Net cash provided by (used in) financing activities	(183,819		)	(189,846		)
Net increase (decrease) in cash and cash equivalents	(21,073		)	(23,475		)
Cash and cash equivalents at beginning of period	28,878			42,494
Cash and cash equivalents at end of period	$	7,805		$	19,019
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	163,228		$	164,310
Cash payments (refunds) for income taxes	—			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	54,419		$	47,151

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

8

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Operating revenue:
Electric	$	529,807		$	497,152		$	1,198,792		$	1,127,343
Natural gas	180,105			163,443			580,169			486,851
Other	9,855			7,574			18,038			16,672
Total operating revenue	719,767			668,169			1,796,999			1,630,866
Operating expenses:
Energy costs:
Purchased electricity	129,799			118,551			309,381			261,448
Electric generation fuel	34,163			40,930			85,473			95,123
Residential exchange	(15,121		)	(13,376		)	(38,568		)	(33,516		)
Purchased natural gas	63,183			48,273			215,984			171,376
Unrealized (gain) loss on derivative instruments, net	3,834			(46,724		)	23,121			(63,546		)
Utility operations and maintenance	145,555			138,018			297,618			284,008
Non-utility expense and other	9,374			8,822			17,865			17,856
Depreciation and amortization	119,457			111,273			234,710			218,787
Conservation amortization	25,691			22,540			60,453			55,751
Taxes other than income taxes	77,032			67,871			195,731			170,163
Total operating expenses	592,967			496,178			1,401,768			1,177,450
Operating income (loss)	126,800			171,991			395,231			453,416
Other income (expense):
Other income	6,126			7,077			12,086			13,052
Other expense	(2,042		)	(2,122		)	(3,257		)	(3,462		)
Interest charges:
AFUDC	2,555			2,603			4,730			4,962
Interest expense	(59,991		)	(60,647		)	(120,453		)	(121,422		)
Income (loss) before income taxes	73,448			118,902			288,337			346,546
Income tax (benefit) expense	22,794			38,002			94,591			109,140
Net income (loss)	$	50,654		$	80,900		$	193,746		$	237,406

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

9

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net income (loss)	$	50,654	$	80,900	$	193,746	$	237,406
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and post-retirement plans, net of tax of $1,143, $1,260, $2,875, and $2,520, respectively	2,123		2,340		5,339		4,680
Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $86, and $86, respectively	79		79		158		158
Other comprehensive income (loss)	2,202		2,419		5,497		4,838
Comprehensive income (loss)	$	52,856	$	83,319	$	199,243	$	242,244

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

10

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

ASSETS

	June 30, 2017			December 31, 2016
Utility plant (at original cost, including construction work in progress of $505,334 and $420,278, respectively):
Electric plant	$	9,952,520		$	9,813,169
Natural gas plant	3,764,503			3,640,271
Common plant	711,266			632,718
Less:  Accumulated depreciation and amortization	(5,073,076		)	(4,927,602		)
Net utility plant	9,355,213			9,158,556
Other property and investments:
Other property and investments	78,928			77,960
Total other property and investments	78,928			77,960
Current assets:
Cash and cash equivalents	7,452			28,481
Restricted cash	12,048			12,418
Accounts receivable, net of allowance for doubtful accounts of $9,977 and $9,798, respectively	257,745			344,964
Unbilled revenue	115,945			234,053
Purchased gas adjustment receivable	—			2,785
Materials and supplies, at average cost	100,772			106,378
Fuel and natural gas inventory, at average cost	54,378			56,851
Unrealized gain on derivative instruments	16,078			54,341
Prepaid expense and other	29,146			43,046
Total current assets	593,564			883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,085			71,517
Power cost adjustment mechanism	4,505			4,531
Other regulatory assets	1,004,303			1,034,352
Unrealized gain on derivative instruments	4,505			8,738
Other	62,589			58,109
Total other long-term and regulatory assets	1,146,987			1,177,247
Total assets	$	11,174,692		$	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

	June 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	501,967			359,795
Accumulated other comprehensive income (loss), net of tax	(140,014		)	(145,511		)
Total common shareholder’s equity	3,637,917			3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,162,000			3,362,000
Pollution control bonds	161,860			161,860
Junior subordinated notes	250,000			250,000
Debt discount, issuance costs and other	(27,669		)	(28,974		)
Total long-term debt	3,546,191			3,744,886
Total capitalization	7,184,108			7,235,134
Current liabilities:
Accounts payable	245,171			317,043
Short-term debt	5,000			245,763
Current maturities of long-term debt	202,412			2,412
Purchased gas adjustment payable	10,980			—
Accrued expenses:
Taxes	102,132			111,428
Salaries and wages	39,245			49,749
Interest	48,232			48,087
Unrealized loss on derivative instruments	44,031			44,170
Other	87,756			71,996
Total current liabilities	784,959			890,648
Other long-term and regulatory liabilities:
Deferred income taxes	1,829,508			1,732,390
Unrealized loss on derivative instruments	18,237			16,261
Regulatory liabilities	619,736			653,296
Other deferred credits	738,144			769,351
Total other long-term and regulatory liabilities	3,205,625			3,171,298
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	11,174,692		$	11,297,080

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

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PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30,
	2017			2016
Operating activities:
Net income (loss)	$	193,746		$	237,406
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	234,710			218,787
Conservation amortization	60,453			55,751
Deferred income taxes and tax credits, net	94,590			108,589
Net unrealized (gain) loss on derivative instruments	23,121			(63,546		)
AFUDC – equity	(6,766		)	(7,048		)
Funding of pension liability	(18,000		)	(9,000		)
Regulatory assets and liabilities	(44,731		)	(120,615		)
Other long-term assets and liabilities	(13,202		)	16,820
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	205,327			184,700
Materials and supplies	5,606			(18,594		)
Fuel and natural gas inventory	2,473			4,974
Prepayments and other	13,900			(2,738		)
Purchased gas adjustment	13,765			(1,027		)
Accounts payable	(49,478		)	(64,132		)
Taxes payable	(9,296		)	(13,230		)
Other	(6,542		)	1,567
Net cash provided by (used in) operating activities	699,676			528,664
Investing activities:
Construction expenditures – excluding equity AFUDC	(431,536		)	(303,834		)
Restricted cash	370			(2,179		)
Other	(6,205		)	(1,707		)
Net cash provided by (used in) investing activities	(437,371		)	(307,720		)
Financing activities:
Change in short-term debt, net	(240,763		)	(123,004		)
Dividends paid	(51,574		)	(128,674		)
Other	9,003			7,456
Net cash provided by (used in) financing activities	(283,334		)	(244,222		)
Net increase (decrease) in cash and cash equivalents	(21,029		)	(23,278		)
Cash and cash equivalents at beginning of period	28,481			41,856
Cash and cash equivalents at end of period	$	7,452		$	18,578
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	112,801		$	113,438
Cash payments (refunds) for income taxes	—			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	54,419		$	47,151

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) Summary of Consolidation 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 June 30, 2017, Puget LNG has incurred $65.2 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 PSE’s financial statements 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.

Non-Utility Property, Plant and Equipment

For PSE, the costs of other property, plant and equipment are stated at historical cost.  Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized.  Replacements of minor items are expensed on a current basis.  Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings.  However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings.

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, the $65.1 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, the construction work in progress of $57.4 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

(2)  New Accounting Pronouncements

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

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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 plans to 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. The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected, and implement the new revenue recognition guidance. After a substantial evaluation of this standard, the Company does not anticipate significant impacts to its results of operations or on its consolidated financial statements. The Company is still waiting on the resolution of certain industry implementation issues to determine the full impact. The Company is anticipating additional future disclosures related to the implementation of the new standard.

Lease Accounting

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". 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. 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 plans to adopt ASU 2016-02 during the first quarter of fiscal year 2019.  At this time, the Company is still evaluating the impact this standard will have on its consolidated financial statements.

Definition of a Business

In January 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business". These amendments clarify the definition of a business. The amendments affect 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. The Company plans to adopt ASU 2017-01 during the first quarter of fiscal year 2018 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Other Income

In February 2017, the FASB issued ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets". The amendments clarify that a financial asset is within the scope of Subtopic 610-20 if it meets the definition of an in substance nonfinancial asset. The amendments also define the term, "in substance nonfinancial asset". The amendments clarify that an entity should identify each distinct nonfinancial asset or in substance nonfinancial asset promised to a counterparty and derecognize each asset when a counterparty obtains control of it.

This amendment is effective for fiscal years beginning after December 15, 2017. The Company plans to adopt ASU 2017-05 during the first quarter of fiscal year 2018 and is in the process of evaluating the potential impacts, if any, of this new guidance on its 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 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Additionally, the line item used in the income statement to present the other components of net benefit cost must be disclosed.

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This amendment is effective for fiscal years beginning after December 15, 2017. 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 plans to adopt ASU 2017-07 during the first quarter of fiscal year 2018 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

(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 June 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 June 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	*		12,246		40,235		*	36,460		41,329
Natural gas derivatives (MMBtus)4	310.6 million		8,337		22,033		336.4 million	26,619		19,101
Total derivative contracts	**		$	20,583	$	62,268	**	$	63,079	$	60,571
Current	**		$	16,078	$	44,031	**	$	54,341	$	44,310
Long-term	**		4,505		18,237		**	8,738		16,261
Total derivative contracts	**		$	20,583	$	62,268	**	$	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 180.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.9 million Megawatt Hours (MWhs) at June 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

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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 June 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	$	20,583	$	—	$	20,583	$	(16,452	)	$	—		$	4,131
Liabilities:
Energy derivative contracts	62,268		—		62,268		(16,452		)	(154		)	45,662

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 June 30,						Six Months Ended June 30,
(Dollars in Thousands)	Location	2017			2016			2017			2016
Interest rate contracts1:
	Non-hedged interest rate swap (expense) income	$	—		$	(359	)	$	28		$	(1,213	)
Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	(5,746		)	45,317			(21,882		)	50,830
Realized	Electric generation fuel	(2,822		)	(12,327		)	(8,020		)	(33,010		)
Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	1,912			1,407			(1,239		)	12,716
Realized	Purchased electricity	(3,923		)	(3,576		)	(10,078		)	(14,795		)
Total gain (loss) recognized in income on derivatives		$	(10,579	)	$	30,462		$	(41,191	)	$	14,528

_______________

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 June 30, 2017, approximately 97.7% 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 2.3% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of June 30, 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 June 30, 2017, PSE had cash posted as collateral of $0.5 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

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collateral requirements with any of its counterparties during the six months ended June 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 June 30, 2017:

Puget Energy and Puget Sound Energy
(Dollars in Thousands)	At June 30, 2017						At December 31, 2016
	Fair Value1		Posted		Contingent		Fair Value1		Posted		Contingent
Contingent Feature	Liability		Collateral		Collateral		Liability		Collateral		Collateral
Credit rating2	$	7,076	$	—	$	7,076	$	4,894	$	—	$	4,894
Requested credit for adequate assurance	24,407		—		—		7,427		—		—
Forward value of contract3	171		530		—		507		—		—
Total	$	31,654	$	530	$	7,076	$	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

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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 $50.2 million and $49.1 million at June 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 June 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	$	236,977	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount1	2	5,098,506		6,444,404		5,091,593		6,337,287
Long-term debt (variable-rate)	2	60,554		60,554		12,480		12,480
Total liabilities		$	5,409,060	$	6,741,935	$	5,354,073	$	6,560,028

Puget Sound Energy		At June 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	$	236,977	$	250,000	$	210,261
Long-term debt (fixed-rate), net of discount2	2	3,498,603		4,465,055		3,497,298		4,360,783
Total liabilities		$	3,748,603	$	4,702,032	$	3,747,298	$	4,571,044

_______________

¹  The carrying value includes debt issuances costs of $30.4 million, and $33.0 million for June 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

²  The carrying value includes debt issuances costs of $25.9 million, and $27.2 million for June 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

Puget Energy and	Fair Value						Fair Value
Puget Sound Energy	At June 30, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,793	$	4,453	$	12,246	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	4,737		3,600		8,337		23,316		3,303		26,619
Total assets	$	12,530	$	8,053	$	20,583	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments1	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	36,425		3,810		40,235		36,507		4,822		41,329
Natural gas derivative instruments	19,889		2,144		22,033		16,423		2,678		19,101
Total liabilities	$	56,314	$	5,954	$	62,268	$	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 June 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	$	3,788		$	1,752		$	5,540		$	1,602		$	(1,622	)	$	(20	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings1	339			—			339			(1,954		)	—			(1,954		)
Included in regulatory assets / liabilities	—			1,124			1,124			—			1,562			1,562
Settlements	(2,508		)	(1,974		)	(4,482		)	(494		)	(879		)	(1,373		)
Transferred into Level 3	—			—			—			—			—			—
Transferred out of Level 3	(976		)	554			(422		)	(2,216		)	455			(1,761		)
Balance at end of period	$	643		$	1,456		$	2,099		$	(3,062	)	$	(484	)	$	(3,546	)

21

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	Six Months Ended June 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 earnings2	1,045			—			1,045			2,654			—			2,654
Included in regulatory assets / liabilities	—			3,582			3,582			—			3,082			3,082
Settlements	(3,838		)	(3,304		)	(7,142		)	(554		)	(1,816		)	(2,370		)
Transferred into Level 3	2,191			(553		)	1,638			(2,080		)	—			(2,080		)
Transferred out of Level 3	273			1,106			1,379			4,263			633			4,896
Balance at end of period	$	643		$	1,456		$	2,099		$	(3,062	)	$	(484	)	$	(3,546	)

______________

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 $0.5 million and $(2.5) million for the three months ended June 30, 2017 and 2016, respectively.

²  Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.7 millionand $3.1 million for the six months ended June 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 June 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	$	4,453	$	3,810	Discounted cash flow	Power prices	$13.00 per MWh	$32.65 per MWh	$24.41 per MWh
Natural gas	$	3,600	$	2,144	Discounted cash flow	Natural gas prices	$1.47 per MMBtu	$3.14 per MMBtu	$2.41 per MMBtu

_______________

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	$11.86 per MWh	$33.52 per MWh	$27.61 per MWh
Natural gas	$	3,303	$	2,678	Discounted cash flow	Natural gas prices	$2.00 per MMBtu	$3.24 per MMBtu	$2.42 per MMBtu

_______________

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

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At June 30, 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 $1.0 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 June 30, 2017, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. However, 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, the following impairments totaling $80.3 million were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:

Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
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 impairment		$	255,875	$	175,542	$	80,333

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

(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 six months ended June 30, 2017 and 2016:

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,023		$	4,605		$	228	$	271	$	16		$	24
Interest cost	7,088			7,226			571		582		130			157
Expected return on plan assets	(11,942		)	(11,687		)	—		—		(116		)	(111		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—
Amortization of net loss (gain)	—			—			269		228		(88		)	(29		)
Net periodic benefit cost	$	(326	)	$	(351	)	$	1,079	$	1,092	$	(58	)	$	41

Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	10,040		$	9,209		$	457	$	542	$	36		$	49
Interest cost	14,186			14,452			1,143		1,163		250			313
Expected return on plan assets	(23,892		)	(23,374		)	—		—		(231		)	(222		)
Amortization of prior service cost	(990		)	(990		)	22		22		—			—
Amortization of net loss (gain)	—			—			538		456		(201		)	(58		)
Net periodic benefit cost	$	(656	)	$	(703	)	$	2,160	$	2,183	$	(146	)	$	82

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,023		$	4,605		$	228	$	271	$	16		$	24
Interest cost	7,088			7,226			571		582		130			157
Expected return on plan assets	(11,963		)	(11,736		)	—		—		(116		)	(111		)
Amortization of prior service cost	(393		)	(393		)	11		11		—			—
Amortization of net loss (gain)	3,095			3,740			392		333		(148		)	(90		)
Net periodic benefit cost	$	2,850		$	3,442		$	1,202	$	1,197	$	(118	)	$	(20	)

25

Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	10,040		$	9,209		$	457	$	542	$	36		$	49
Interest cost	14,186			14,452			1,143		1,163		250			313
Expected return on plan assets	(23,931		)	(23,472		)	—		—		(231		)	(222		)
Amortization of prior service cost	(787		)	(786		)	22		22		—			—
Amortization of net loss (gain)	6,524			7,480			783		666		(320		)	(180		)
Net periodic benefit cost	$	6,032		$	6,883		$	2,405	$	2,393	$	(265	)	$	(40	)

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

Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
	Six Months Ended			Year Ended			Six Months Ended			Year Ended			Six Months Ended			Year Ended
(Dollars in Thousands)	June 30, 2017			December 31, 2016			June 30, 2017			December 31, 2016			June 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	10,040			18,913			457			1,085			36			93
Interest cost	14,186			28,689			1,143			2,325			250			533
Actuarial loss (gain)	(253		)	1,545			—			106			373			(2,262		)
Benefits paid	(20,894		)	(38,730		)	(955		)	(3,061		)	(572		)	(1,264		)
Medicare part D subsidy received	—			—			—			—			100			148
Administrative Expense	—			(898		)	—			—			—			—
Benefit obligation at end of period	$	655,686		$	652,607		$	52,379		$	51,734		$	11,381		$	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 June 30, 2017, the Company contributed $9.0 million, $0.5 million and $0.1 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the six months ended June 30, 2017, the Company contributed $18.0 million, $1.0 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

26

in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update 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. 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.

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. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. 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.

27

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 $11.4 million for electric and $2.1 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 six months ended June 30, 2017 and June 30, 2016, PSE incurred $20.8 million and $15.6 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.1 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.

28

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 six months ended June 30, 2017, PSE under recovered its power costs by $8.6 million of which no amount was apportioned to customers.  This compares to an under recovery of power costs of $3.1 million for the six months ended June 30, 2016 of which no amounts were apportioned to customers. Load increased in 2017 compared to 2016 which was offset by a decrease in the total baseline rate and an increase in costs. Additionally, this change was due to the new 2017 mechanism which 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 fixed 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.

29

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 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, 2017	0.3%	$(51.7)
January 1, 2016	(0.2)	(57.3)

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 Commission's Order 4 in PSE’s 2014 PCORC under Docket No. UE-141141 and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE's GRC. This allowed PSE to implement the December 1, 2016 price and volume changes associated with the Centralia Coal Transition purchase power agreement through a compliance filing.

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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.

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The following table sets forth CRM rate adjustments as originally proposed by PSE 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	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2017, proposed	0.6%	$5.4
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 adjustment 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, 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 United States 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 six months ended June 30, 2017, the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.0 million for Colstrip Units 1 and 2 and $13.3 million for Colstrip Units 3 and 4.

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

Puget Sound Energy
(Dollars in Thousands)	Changes in ARO
Balance at December 31, 2016	$	200,345
New asset retirement obligation recognized in the period	—
Liability adjustments	(136		)
Revisions in estimated cash flows	(18,329		)
Accretion expense	2,746
Balance at June 30, 2017	$	184,626

(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. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. 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 Colstrip 1 and 2 owners, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), 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 $175.2 million as of June 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 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 completed a comprehensive inspection and remediation program. The settlement was presented to the Washington Commission during a scheduled hearing on May 15, 2017. 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.

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 $0.5 million and $0.7 million relating to these claims as of June 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 six months ended June 30, 2017, the Company entered into new power supply and service contracts with estimated payment obligations totaling $703.2 million through 2028.

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

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

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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.

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. The 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. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. 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 $11.4 million and a reduction in natural gas decoupling deferral and revenue of $2.1 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 June 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 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.

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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 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);

• 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.

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For the six months ended June 30, 2017, PSE under recovered its power costs by $8.6 million of which no amount was apportioned to customers.  This compares to an under recovery of power costs of $3.1 million for the six months ended June 30, 2016 of which no amounts were apportioned to customers. Load increased in 2017 compared to 2016 which was offset by a decrease in the total baseline rate and an increase in costs. Additionally, this change was due to the new 2017 mechanism which 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 fixed 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 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.

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 June 1, 2017, PSE filed with the Washington Commission 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 $5.4 million, or 0.6%, annually.

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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 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. PSE's credit facilities mature in 2019 and Puget Energy's senior secured credit facility matures in 2018. For additional information, see discussion on credit facilities in Part 1, Item 2, “Puget Sound Energy - Credit Facilities” and "Puget Energy - Credit Facility".

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. 

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Results of Operations

Puget Sound Energy

Non-GAAP Financial Measures - Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.”  Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a departure from GAAP presentation.  The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance.  Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers 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 June 30,									Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Electric operating revenue:
Residential sales	$	253,011		$	231,345		$	21,666		$	637,834		$	576,176		$	61,658
Commercial sales	202,738			197,668			5,070			441,070			429,394			11,676
Industrial sales	25,844			24,975			869			55,581			54,677			904
Other retail sales	4,801			4,868			(67		)	9,695			10,202			(507		)
Total retail sales	486,394			458,856			27,538			1,144,180			1,070,449			73,731
Transportation sales	2,651			2,779			(128		)	5,714			5,622			92
Sales to other utilities and marketers	5,979			10,729			(4,750		)	14,687			17,538			(2,851		)
Decoupling revenue	24,358			15,783			8,575			11,581			34,476			(22,895		)
Other decoupling revenue1	(4,682		)	4,538			(9,220		)	(7,698		)	(2,663		)	(5,035		)
Other	15,107			4,467			10,640			30,328			1,921			28,407
Total electric operating revenues2	529,807			497,152			32,655			1,198,792			1,127,343			71,449
Minus electric energy costs:
Purchased electricity2	129,799			118,551			11,248			309,381			261,448			47,933
Electric generation fuel2	34,163			40,930			(6,767		)	85,473			95,123			(9,650		)
Residential exchange2	(15,121		)	(13,376		)	(1,745		)	(38,568		)	(33,516		)	(5,052		)
Total electric energy costs	148,841			146,105			2,736			356,286			323,055			33,231
Electric margin3	$	380,966		$	351,047		$	29,919		$	842,506		$	804,288		$	38,218
Electric Energy Sales, MWh
Residential sales	2,227,999			2,062,717			165,282			5,704,408			5,175,549			528,859
Commercial sales	2,129,016			2,083,751			45,265			4,512,612			4,370,929			141,683
Industrial sales	289,516			284,081			5,435			597,596			591,171			6,425
Other retail sales	20,840			21,362			(522		)	44,338			46,096			(1,758		)
Total energy sales to customers	4,667,371			4,451,911			215,460			10,858,954			10,183,745			675,209

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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 June 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased $32.7 million primarily due to higher retail sales of $27.5 million, other electric operating revenues of $10.6 million and decoupling revenue of $8.6 million; partially offset by a decrease in other decoupling revenue of $9.2 million.  These items are discussed in detail below.

• Electric retail sales increased $27.5 million primarily due to a $22.2 million increase in retail electricity usage of 215,460 Megawatt Hour (MWhs) and an increase in rates of $5.3 million.

• Decoupling revenue increased $8.6 million an increase of $16.2 million of fixed cost deferrals previously recorded within the PCA mechanism, offset by a decrease of $7.6 million associated with less decoupled revenues in excess of actual customer billings as compared to 2016.

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• Other decoupling revenue decreased $9.2 million due to increased rate of return (ROR) excess earnings of $7.4 million and an increase of decoupling cash collections of $2.5 million as compared to 2016.

• Other electric operating revenue increased $10.6 million primarily due to a PTC deferral of $5.7 million in 2016 as compared to no PTC deferral in 2017 and an increase in net non-core gas sales of $5.0 million.

Electric Energy Costs

• Purchased electricity expense increased $11.2 million primarily due to a $9.6 million increase primarily related to firm purchases from TransAlta Centralia and a $3.7 million increase in energy imbalance market (EIM) purchases compared to 2016. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. The increases were partially offset by a decrease of $4.4 million of secondary purchases.

• Electric generation fuel expense decreased $6.8 million due to a number of factors including a $2.2 million decrease in financial losses on natural gas fuel in 2017 as compared to 2016, a $2.1 million decrease in the lower of cost or market inventory adjustment for coal recorded in 2017 compared to 2016, and a $1.4 million decrease in the cost of coal burned. The decrease in the cost of coal burned was driven by a decrease in the average price of coal in 2017 compared to 2016 and offset by an increase in the volume of coal burned in 2017.      

Six Months Ended June 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased $71.4 million primarily due to higher retail sales of $73.7 million and other operating revenues of $28.4 million; partially offset by decreases in decoupling revenue of $22.9 million and other decoupling adjustments of $5.0 million. These items are discussed in detail below.

• Electric retail sales increased $73.7 million primarily due to a $71.0 million increase in retail electricity usage of 675,209 Megawatt Hour (MWhs) and an increase in rates of $2.8 million.

• Decoupling revenue decreased $22.9 million due to a decrease in allowed decoupled revenues in excess of actual customer billings as compared to 2016.

• Other decoupling revenue decreased $5.0 million primarily due to an increase in decoupling cash collections of $6.3 million; partially offset by a decrease of 24-month revenue reserve of $2.0 million as compared to 2016.

• Other electric operating revenue increased $28.4 million primarily due to an increase in net non-core gas sales of $19.1 million and a PTC deferral of $10.8 million in 2016 as compared to no PTC deferral in 2017.

Electric Energy Costs

• Purchased electricity expense increased $47.9 million primarily due to a $19.7 million increase related to firm purchases from TransAlta Centralia, an increase of $9.4 million of secondary purchases, an $8.4 million increase in EIM purchases, and an $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.

• Electric generation fuel expense decreased $9.7 million primarily due to a $7.8 million decrease in financial losses on natural gas fuel in 2017 as compared to 2016 and a $2.1 million decrease in the lower of cost or market inventory adjustment for coal recorded in 2017 compared to 2016. 

• Residential exchange credits increased $5.1 million resulting from higher Residential Exchange Program (REP) credits associated with the BPA REP settlement. 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.

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Natural Gas Margin

Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE's service territory. The following table displays the details of PSE's natural gas margin:

Natural Gas Margin	Three Months Ended June 30,									Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Natural gas operating revenue:
Residential sales	$	120,052		$	92,099		$	27,953		$	401,933		$	309,830		$	92,103
Commercial sales	55,370			44,125			11,245			158,099			125,273			32,826
Industrial sales	4,281			3,627			654			11,868			10,393			1,475
Total retail sales	179,703			139,851			39,852			571,900			445,496			126,404
Transportation sales	5,385			5,018			367			10,932			10,111			821
Decoupling revenue	2,888			15,979			(13,091		)	(3,357		)	36,030			(39,387		)
Other decoupling revenue1	(11,024		)	(297		)	(10,727		)	(5,617		)	(10,661		)	5,044
Other	3,153			2,892			261			6,311			5,875			436
Total natural gas operating revenues2	180,105			163,443			16,662			580,169			486,851			93,318
Minus purchased natural gas energy costs2	63,183			48,273			14,910			215,984			171,376			44,608
Natural gas margin3	$	116,922		$	115,170		$	1,752		$	364,185		$	315,475		$	48,710
Natural Gas Volumes
(Therms in Thousands):
Residential	98,526			72,506			26,020			370,175			286,531			83,644
Commercial firm	52,135			41,387			10,748			162,585			127,467			35,118
Industrial firm	5,241			4,394			847			14,397			12,389			2,008
Interruptible	12,627			8,582			4,045			27,044			24,377			2,667
Total retail natural gas volumes, therms	168,529			126,869			41,660			574,201			450,764			123,437
Transportation volumes	56,261			56,164			97			119,049			118,249			800
Total natural gas volumes	224,790			183,033			41,757			693,250			569,013			124,237

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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.

Three Months Ended June 30, 2017 compared to 2016

Natural Gas Operating Revenue

Natural gas operating revenue increased $16.7 million primarily due to an increase of $39.9 million in total retail sales due to an increase of natural gas usage; partially offset by a $13.1 million reduction in decoupling revenue and a decrease of $10.7 million in other decoupling revenue. These items are discussed in detail below.

• Natural gas retail sales revenue increased $39.9 million primarily due to an increase of $45.9 million from an additional 41,660 of therms sold; partially offset by a decrease of $6.1 million due to rate adjustments.

• Decoupling revenue decreased $13.1 million due to a decrease in allowed decoupled revenues in excess of actual customer billings as compared to 2016.

• Other decoupling revenue decreased $10.7 million primarily due to increased ROR excess earnings sharing of $9.0 million and increased decoupling cash collections of $2.8 million as compared to 2016.

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Natural Gas Energy Costs

Purchased natural gas expense increased $14.9 million primarily due to an increase in natural gas usage.

Six Months Ended June 30, 2017 compared to 2016

Natural Gas Operating Revenue

Natural gas operating revenue increased $93.3 million primarily due to an increase of $126.4 million in total retail sales due to additional natural gas usage and an increase in other decoupling revenue of $5.0 million; partially offset by a $39.4 million reduction in decoupling revenue. These items are discussed in detail below.

• Natural gas retail sales revenue increased $126.4 million primarily due to an increase of $122.0 million from an additional 123,437 of therms sold and an increase of $4.4 million due to rate adjustments.

• Decoupling revenue decreased $39.4 million due to a decrease in allowed decoupled revenues in excess of actual customer billings as compared to the prior period.

• Other decoupling revenue increased $5.0 million due to the recognition of the 24-month revenue reserve, previously unrecognized, of $20.2 million. The increase was partially offset by an increase in decoupling cash collections of $13.1 and an increase in ROR excess earning sharing of $2.1 million as compared to 2016.

Natural Gas Energy Costs

Purchased natural gas expense increased $44.6 million primarily due to an 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 six months ended June 30, 2017 and 2016:

Puget Sound Energy	Three Months Ended June 30,									Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
Operating expenses:
Net unrealized (gain) loss on derivative instruments	$	3,834		$	(46,724	)	$	50,558		$	23,121		$	(63,546	)	$	86,667
Utility operations and maintenance	145,555			138,018			7,537			297,618			284,008			13,610
Non-utility expense and other	9,374			8,822			552			17,865			17,856			9
Depreciation and amortization	119,457			111,273			8,184			234,710			218,787			15,923
Conservation amortization	25,691			22,540			3,151			60,453			55,751			4,702
Taxes other than income taxes	77,032			67,871			9,161			195,731			170,163			25,568
Other income (deductions):
Other income	6,126			7,077			(951		)	12,086			13,052			(966		)
Other expense	(2,042		)	(2,122		)	80			(3,257		)	(3,462		)	205
Interest expense	(57,436		)	(58,044		)	608			(115,723		)	(116,460		)	737
Income tax expense	22,794			38,002			(15,208		)	94,591			109,140			(14,549		)

Three Months Ended June 30, 2017 compared to 2016

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments decreased $50.6 million to a loss of $3.8 million. The net loss for the three months ended June 30, 2017 was comprised of a loss of $5.7 million related to natural gas for power derivative instruments and a $1.9 million gain related to electricity derivative instruments.  This compares to a gain of $45.3 million related to natural gas for power derivative instruments and a gain of $1.4 million related to electricity derivative instruments, respectively, during the three months ended June 30, 2016.  The overall loss was primarily due to a decrease in the gain from settlements and a decrease in the quarter-to-date change of natural gas and wholesale electricity forward prices from June 30, 2016 to June 30, 2017. If the market price is less than book price for purchases it results in a loss. The majority of the Company's hedging portfolio is made up of purchase transactions.

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• Utility operations and maintenance expense increased $7.5 million, primarily due to increases in administrative and general operations and maintenance expense of $10.8 million primarily due to rents, electric maintenance of general plant, injuries and damages and pension expenses; partially offset by a decrease in electric transmission and distribution, natural gas operations, customer services and administrative and general expense of $3.4 million.

• Depreciation and amortization expense increased $8.2 million primarily due to $2.1 million of depreciation expense related to net additions of $176.2 million of electric distribution and general assets, an increase of $1.7 million related to an additional $186.0 million of natural gas distribution assets, and an increase of $3.8 million of amortization expense related to an increase of computer software assets.

• Taxes other than income taxes increased $9.2 million primarily due to an increase in municipal taxes of $3.4 million due to increased revenue, an increase in state excise taxes of $2.8 million and an increase of $2.4 million in property taxes due to increased revenue and load.

Other Income, Interest Expense and Income Tax Expense

• Income tax expense decreased $15.2 million primarily driven by lower pre-tax income.

Six Months Ended June 30, 2017 compared to 2016

Other Operating Expenses

• Net unrealized (gain) loss on derivative instruments decreased $86.7 million to a loss of $23.1 million. The net loss for the six months ended June 30, 2017 was comprised of a loss of $21.9 million related to natural gas for power derivative instruments and a $1.2 million loss related to electricity derivative instruments.  This compares to a gain of $50.8 million related to natural gas for power derivative instruments and a gain of $12.7 million related to electricity derivative instruments during the six months ended June 30, 2016. The overall loss was primarily due to a decrease in natural gas and wholesale electricity forward prices from June 30, 2016 to June 30, 2017. The majority of the Company's hedging portfolio is made up of purchase transactions.

• Utility operations and maintenance expense increased $13.6 million, which was primarily due to the following: increases in administrative and general and customer service expense of $20.3 million primarily due to customer records, collections, low income programs, rents, employee pension and benefits, injuries and damage, electric maintenance of general plant and outside services expense. This was partially offset by a decrease in electric transmission, distribution and natural gas operation expense of $6.5 million primarily related to distribution operations supervision and engineering, meter, distribution maintenance of underground lines and monitoring expenses and operation of load dispatch.

• Depreciation and amortization expense increased $15.9 million primarily due to $8.0 million of depreciation expense due to net additions of $176.2 million, an increase of $3.3 million due to net additions of $186.0 million of natural gas distribution assets and an increase of $7.7 million of amortization expense related to an increase of computer software assets.

• Taxes other than income taxes increased $25.6 million primarily due to an increase of $8.9 million in property taxes due to increased revenue and load, an increase in municipal taxes of $8.9 million due to increased revenue and an increase in state excise taxes of $7.8 million.

Other Income, Interest Expense and Income Tax Expense

• Income tax expense decreased $14.5 million primarily driven by lower pre-tax income.

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Puget Energy

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

Benefit/(Expense)	Three Months Ended June 30,									Six Months Ended June 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change
PSE net income	$	50,654		$	80,900		$	(30,246	)	$	193,746		$	237,406		$	(43,660	)
Non-utility expense and other	3,231			3,644			(413		)	6,526			7,043			(517		)
Other income (deductions)	136			—			136			137			—			137
Non-hedged interest rate swap (expense)	—			(359		)	359			28			(1,213		)	1,241
Interest expense1	(28,417		)	(28,029		)	(388		)	(56,538		)	(56,067		)	(471		)
Income tax benefit (expense)	9,671			8,397			1,274			18,926			18,570			356
Puget Energy net income (loss)	$	35,275		$	64,553		$	(29,278	)	$	162,825		$	205,739		$	(42,914	)

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

Summary Results of Operation

Three and Six Months Ended June 30, 2017 compared to 2016

Puget Energy’s net income decreased for the three and six months ended June 30, 2017 by $29.3 million and $42.9 million, respectively, which is primarily due to PSE's decrease in net income of $30.2 million and $43.7 million, respectively. 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 six months ended June 30, 2017, the Company has entered into two new power supply and service contracts with estimated payment obligations totaling $703.2 million through 2028.

The following are the Company's aggregate availability under commercial commitments as of June 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	739,446			—		739,446		—		—
Less: Inter-company short-term debt elimination2,3	(30,000		)	—		—		—		(30,000		)
Total Puget Energy commercial commitments	$	1,739,446		$	—	$	1,739,446	$	—	$	—

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

²   For more information, see "Financing Program - Puget Sound Energy - Demand Promissory Note - in the Management's Discussion and Analysis section".

³  For more information, see "Financing Program - Puget Energy - Credit Facility - in the Management's Discussion and Analysis section".

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Off-Balance Sheet Arrangements

As of June 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.

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 deliver, meet regulatory requirements, and customer growth.  Construction expenditures, excluding equity allowance for funds used during construction (AFUDC), totaled 431.5 million for the six months ended June 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 cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  

Capital Resources

Cash from Operations

Puget Sound Energy	Six Months Ended June 30, 2017
(Dollars in Millions)	2017			2016			Change
Net income	$	193,746		$	237,406		$	(43,660	)
Non-cash items1	406,108			312,533			93,575
Changes in cash flow resulting from working capital2	175,755			91,520			84,235
Regulatory assets and liabilities	(44,731		)	(120,615		)	75,884
Other noncurrent assets and liabilities	(31,202		)	7,820			(39,022		)
Net cash provided by operating activities	$	699,676		$	528,664		$	171,012

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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.

Six Months Ended June 30, 2017 compared to 2016

Cash generated from operations for the six months ended June 30, 2017 increased by $171.0 million including a net income decrease of $43.7 million. The following are significant factors that impacted PSE's cash flows from operations:

• Cash flow resulting from non-cash items increased $93.6 million primarily due to changes in derivative instruments of 86.7 million.

• Cash flow resulting from working capital increased $84.2 million due to changes in accounts receivable, unbilled revenue, materials and supplies, prepayments, purchased gas adjustments and accounts payable.

• Cash flow resulting from regulatory assets and liabilities increased $75.9 million primarily due to changes in power cost adjustments and purchased gas adjustments.

• Cash flow resulting from other noncurrent assets and liabilities decreased $39.0 million primarily due to changes in asset retirement obligations and pension funding partially offset by changes in long-term deferred credits.

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Puget Energy	Six Months Ended June 30, 2017
(Dollars in Millions)	2017			2016			Change
Net income	$	162,825		$	205,739		$	(42,914	)
Non-cash items1	387,042			292,094			94,948
Changes in cash flow resulting from working capital2	167,340			94,498			72,842
Regulatory assets and liabilities	(44,731		)	(120,615		)	75,884
Other noncurrent assets and liabilities	(6,806		)	5,519			(12,325		)
Net cash provided by operating activities	$	665,670		$	477,235		$	188,435

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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.

Six Months Ended June 30, 2017 compared to 2016

Cash generated from operations for the six months ended June 30, 2017 increased by $188.4 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 $11.4 million primarily due to a larger change in accounts receivable.

• Cash flow resulting from other noncurrent assets and liabilities increased $26.7 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

PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have 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% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of June 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 June 30, 2017, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $5.0 million was outstanding under the commercial paper program. Outside of

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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.

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 June 30, 2017, PSE had no outstanding balance under the Note.

Debt Restrictive Covenants

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

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

• Approximately $2.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.1 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 June 30, 2017; and

• Approximately $468.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $780.0 million of natural gas bondable property available for issuance, subject to a minimum combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage) both of which PSE exceeded at June 30, 2017.

At June 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 June 30, 2017, approximately $690.1 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 53.2% at June 30, 2017 and the EBITDA to interest expense was 5.3 to 1.0 for the twelve months ended June 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.

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Puget Energy

Credit Facility

At June 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 June 30, 2017, there was $60.6 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%. For additional information, see Note 6, "Regulation and Rates" to the consolidated financial statements included in Part 1 of this report.

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

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 plus 0.50%. 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 June 30, 2017

At June 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. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. 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 Colstrip 1 and 2 owners, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), 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 $175.2 million as of June 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

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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 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 completed a comprehensive inspection and remediation program. The settlement was presented to the Washington Commission during a scheduled hearing on May 15, 2017. 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.

Regional Haze Rule

On June 15, 2005, the Environmental Protection Agency (EPA) issued the Clean Air Visibility rule to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area.  The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units.  The final Federal Implementation Plan for Montana (FIP) for Regional Haze was issued in September 2012. There are no immediate requirements for Units 3 and 4, but Units 1 and 2 will need to upgrade pollution controls to meet new sulfur dioxide and nitrogen oxide limits. The Sierra Club filed an appeal of the FIP with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) on November 15, 2012 and Talen Energy also filed an appeal as the Colstrip operator.

The case was heard on May 15, 2014 in Seattle, Washington, and the final decision by the Ninth Circuit was issued June 9, 2015. The Ninth Circuit Court of Appeals reviewed the EPA’s first phase requirements for Colstrip and found that the EPA had not adequately justified the need for two of the control technologies and remanded these two issues back to the EPA. The EPA informally indicated that it will wait until the next Regional Haze planning period to reissue a FIP.

The ruling in no way affects the future planning periods for the Regional Haze program or the glide path for the Company. The current EPA assessment is that the state of Montana will require significant emission reductions to meet the natural visibility goal by 2064 which means additional emission reductions will be necessary in future 10-year planning periods, beginning in the 2018-2028 periods, and there is risk and uncertainty regarding potential costs.

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 RCRA, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR 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 initial rule was self-implementing to be enforced by citizen lawsuits rather than the EPA. On December 16, 2016, President Obama signed legislation amending RCRA to allow a state to take over the CCR program. Under the amendment, if a state does not seek approval of a permit program or if the EPA denies a state application, the EPA would be required to adopt a permit program in lieu of the current self-implementing rule, as long as Congress grants the funding for the EPA to do so. This would not eliminate the threat of citizen lawsuits, but could provide more certainty regarding interpretations and ultimate compliance. If no permit program is in effect in a state, the CCR rule will remain self-implementing.

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.

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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. PSE is still reviewing the impact of this development. 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% 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 an action 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 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, LLC (Puget LNG).  Puget LNG, which was formed on November 29, 2016, will have the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility. Puget LNG has entered into one fuel supply agreement with a maritime customer and is marketing the facility’s expected output to other potential customers.

Currently under construction, the Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Commission’s order, Puget LNG will be allocated approximately 57% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43% of the capital and operating costs. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of June 30, 2017, Puget LNG has incurred $65.2 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

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(EMC) establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.

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

Counterparty Credit Risk

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

Interest Rate Risk

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

Item 4.     Controls and Procedures

Puget Energy

Evaluation of Disclosure Controls and Procedures

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

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 June 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 six months ended June 30, 2017. Management monitored developments related to the financial systems modernization

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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 June 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 6.     Exhibits

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

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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/ Daniel A. Doyle
		Daniel A. Doyle Senior Vice President and Chief Financial Officer
Date:	August 2, 2017

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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).
12.1*	Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016 and 12 months ended June 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 June 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 June 30, 2017 filed on August 2, 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.

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