1, 2015. 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 certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014.

On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $10.6 million, or 0.5% annually, and a rate decrease for natural gas customers of $1.0 million, or 0.1% annually.

In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. The customers share of the over earnings will be returned to customers over the subsequent 12-month period beginning May 1 of each year.

Electric Rate Filings

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” is set in part, based on normalized assumptions about weather and hydrological 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 $30.0 million cumulative deferral trigger is reached.

On August 7, 2015, the Washington Commission issued an order approving changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply 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

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.

Federal Incentive Tracker Tariff

The Federal Incentive ~~tracker tariff~~Tracker Tariff passes through to customers the benefits associated with the wind-related treasury ~~grants received by the company and production tax credits available through to its customers.~~grants. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.

~~The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact~~ Rates change annually on ~~PSE’s revenue based on the effective dates:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2016 (0.2 )% $ (57.3 )
January 1, 2015 (0.2 ) (55.2 )
January 1, 2014 (0.3 ) (58.5 )
February 1, 2013 (2.8 ) (58.4 )

~~Power Cost Adjustment Mechanism~~

PSE currently has a PCA mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” included in revenue requirements. The “power cost baseline” is set in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.

~~The graduated scale currently applicable is 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 will not take effect until~~ January ~~1, 2017. Key components of the settlement will result in the following changes to the PCA mechanism:~~

Annual Power Cost Variability Company's Share Customers’ Share
Over Under Over Under
+/- $17 million 100 % 100 % — % — %
+/- $17 million - $40 million 35
50
65
50
+/- $40 + million 10
10
90
90

~~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 as part of the next 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 on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, 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), and agreeing, 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/PCORC.~~

PSE had an unfavorable PCA imbalance during the year ended December 31, 2015, due to under recovering $8.7 million of power costs that exceeded the “power cost baseline” level of which no amounts were apportioned to customers. This compares to an unfavorable imbalance of $40.1 million for the year ended December 31, 2014 of which $10.1 million was apportioned to customers.1.

Power Cost Only Rate Case

A power cost rate case is a limited-scope proceeding ~~was approved in 2002 by the Washington Commission~~ to ~~periodically~~ reset power cost rates. In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission is not required to but historically has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

Residential Exchange Benefit

The ~~following table sets forth PCORC rate adjustments approved by~~residential exchange program passes through the ~~Washington Commission and~~residential exchange program benefits that PSE receives from the ~~corresponding impact~~Bonneville Power Administration (BPA). Rates change bi-annually on ~~PSE’s revenue based on the effective dates:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
December 1, 2014 (0.9 )% $ (19.4 )
November 1, 2013 (0.5 ) (10.5 )
October 1.

Electric Property Tax Tracker Mechanism

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

~~The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding 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, 2015 0.4 % $ 8.4
May 1, 2014 0.5
11.0

~~Conservation Rider~~

~~The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding 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, 2014 0.6 % $ 12.2

Natural Gas Rate Filings

Natural Gas Cost Recovery Mechanism

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

Purchased Gas Adjustment

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

~~The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact~~ Rates change annually 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, 2015 (17.4 )% $ (185.9 )
November 1, 2014 2.5
23.3
November 1, 2013 0.4
4.0

~~Cost Recovery Mechanism~~

The purpose of the Cost Recovery Mechanism (CRM) is to recover depreciation expense and return on the investment in the Company's pipeline replacement program to enhance the safety of the natural gas distribution system until included in base rates for gas service.

~~The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding 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, 2015 0.5 % $ 5.3
November 1, 2014 0.2
2.3
November 1.

Natural Gas Property Tax Tracker Mechanism

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

Natural Gas Conservation Rider

The ~~following table sets forth property tax tracker mechanism rate adjustments approved by~~natural gas conservation rider collects revenue to cover the ~~Washington Commission~~costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the ~~corresponding impact on PSE’s revenue based on~~annual budget that started the ~~effective dates:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
June 1, 2015 (0.2 )% $ (2.3 )
May 1, 2014 0.6
5.6
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.

For additional information on electric and natural gas rates, see ~~Note 3 to the consolidated financial statements~~Management's Discussion and Analysis, "Regulation and Rates" included in Item 87 of this report.

ELECTRIC UTILITY OPERATING STATISTICS


	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2017			2016			2015
Generation and purchased power, MWh
Company-controlled resources	12,747,014			11,640,504			12,421,626			10,825,778			11,577,608			12,747,014
Contracted resources	5,911,012			4,050,062			4,498,204			8,337,348			7,023,786			5,911,012
Non-firm energy purchased	5,315,266			8,001,425			7,565,140			6,147,778			6,005,797			5,315,266
Total generation and purchased power	23,973,292			23,691,991			24,484,970			25,310,904			24,607,191			23,973,292
Less: losses and Company use	(1,514,272		)	(1,724,501		)	(1,581,108		)	(1,568,599		)	(1,547,619		)	(1,514,272		)
Total energy sales, MWh	22,459,020			21,967,490			22,903,862			23,742,305			23,059,572			22,459,020
Electric energy sales, MWh
Residential	10,164,703			10,349,928			10,769,100			10,931,999			10,245,326			10,164,703
Commercial	8,999,068			8,900,863			9,118,720			9,089,842			8,895,950			8,999,068
Industrial	1,257,958			1,226,588			1,229,556			1,214,818			1,223,214			1,257,958
Other customers	94,847			98,499			98,579			87,230			90,753			94,847
Total energy sales to customers	20,516,576			20,575,878			21,215,955			21,323,889			20,455,243			20,516,576
Sales to other utilities and marketers	1,942,444			1,391,612			1,687,907			2,418,416			2,604,329			1,942,444
Total energy sales, MWh	22,459,020			21,967,490			22,903,862			23,742,305			23,059,572			22,459,020
Transportation, including unbilled	2,012,827			2,099,219			2,089,435			2,001,244			2,085,574			2,012,827
Electric energy sales and transportation, MWh	24,471,847			24,066,709			24,993,297			25,743,549			25,145,146			24,471,847
Electric operating revenue by classes
(Dollars in Thousands)
Residential	$	1,061,117		$	1,003,205		$	1,115,694		$	1,232,075		$	1,138,871		$	1,061,117
Commercial	867,786			824,778			847,704			892,360			872,057			867,786
Industrial	114,223			107,750			108,433			112,817			113,469			114,223
Other customers	20,216			19,707			19,192			19,729			20,045			20,216
Total operating revenue from customers	2,063,342			1,955,440			2,091,023			2,256,981			2,144,442			2,063,342
Transportation, including unbilled	10,143			9,502			8,738			12,584			10,937			10,143
Sales to other utilities and marketers	46,666			41,680			54,444			53,789			50,124			46,666
Decoupling revenue	13,630			25,735			(14,989		)	9,975			29,968			13,630
Other decoupling revenue¹	(16,634		)	5,609			—			(27,706		)	(21,168		)	(16,634		)
Miscellaneous operating revenue	11,321			45,831			17,704			115,040			24,189			11,321
Total electric operating revenue	$	2,128,468		$	2,083,797		$	2,156,920		$	2,420,663		$	2,238,492		$	2,128,468
Number of customers served (average):
Residential	970,830			960,708			956,783			998,078			984,739			970,830
Commercial	123,072			121,332			119,833			126,829			125,067			123,072
Industrial	3,434			3,437			3,474			3,399			3,425			3,434
Other	6,283			6,023			5,274			6,722			6,472			6,283
Transportation	16			17			17			16			16			16
Total customers	1,103,635			1,091,517			1,085,381			1,135,044			1,119,719			1,103,635

Off-Balance Sheet Arrangements

As of December 31, ~~2015,~~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.~~condition, other than the items disclosed in Note 8, "Leases" and in Note 15, "Commitment and Contingencies" to the consolidated financial statements included in Item 2 of this report.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG ~~facilities~~facility are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity AFUDC, totaled ~~$587.2~~$963.7 million in ~~2015~~.2017. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:


Capital Expenditure Projections (Dollars in Thousands)	2016		2017		2018
Capital Expenditure Projections
(Dollars in Thousands)							2018		2019		2020
Total energy delivery, technology and facilities expenditures	$	806,655	$	815,989	$	665,462	$	1,003,000	$	839,000	$	740,000

The program is subject to change based upon general business, economic and regulatory conditions. Utility construction expenditures and any new generation resource expenditures are typically funded from a combination of cash from operations, short-term debt, long-term debt and/or equity. PSE’s utility construction program expenditures periodically can and do exceed cash flow generated from operations. As a result, execution of PSE’s utility construction program is dependent, in part, on continued access to capital markets.

Capital Resources

Cash ~~From~~from Operations



Puget Sound Energy	Year Ended December 31,
(Dollars in Millions)	2017			2016			Change
Net income	$	320,054		$	380,581		$	(60,527	)
Non-cash items¹	782,890			631,440			151,450
Changes in cash flow resulting from working capital²	105,281			(46,554		)	151,835
Regulatory assets and liabilities	(88,875		)	(152,786		)	63,911
Other non-current assets and liabilities³	(32,547		)	6,235			(38,782		)
Net cash provided by operating activities	$	1,086,803		$	818,916		$	267,887

_______________


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


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


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

~~Puget Sound Energy~~Year Ended December 31, 2017 compared to 2016

Cash generated from operations for the year ended December 31, ~~2015~~2017 increased by $267.9 million including a net income decrease of $60.5 million. The following are significant factors that impacted PSE's cash flows from operations:

Non-cash items increased $151.5 million primarily due to changes in derivative instruments of $114.6 million, depreciation and amortization of $42.4 million, deferred taxes of $36.1 million and conservation amortization of $13.4 million offset by a decrease of $53.3 million in production tax credits. For further discussion, see Other Operating Expenses in Item 7, Management's Discussion and Analysis and Note 13, "Income Taxes" in Item 8.

Changes in cash flow resulting from working capital increased $151.8 million primarily due to changes in accounts receivable and unbilled revenue of $50.7 million, an increase to the purchased gas adjustment of $34.2 million as discussed previously in the electric and natural gas margin discussion, an increase of $27.5 million in materials and supplies, and an increase of $47.0 million in prepayments.

Regulatory assets and liabilities cash flow increased $63.9 million primarily due to changes in decoupling and derivatives offset by changes in purchased gas adjustments.

Other non-current assets and liabilities cash flow decreased $38.8 million primarily due to an increase in the long-term incentive plan accrual, an increase in major maintenance and inspections, reduced pension funding and other changes in long-term assets and liabilities.



Puget Energy	Year Ended December 31,
(Dollars in Millions)	2017			2016			Change
Net income	$	175,194		$	312,899		$	(137,705	)
Non-cash items¹	837,569			602,535			235,034
Changes in cash flow resulting from working capital²	93,654			(24,936		)	118,590
Regulatory assets and liabilities	(88,875		)	(153,643		)	64,768
Other non-current assets and liabilities³	(45,411		)	(7,565		)	(37,846		)
Net cash provided by operating activities	$	972,131		$	729,290		$	242,841

_______________


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


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


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

Year Ended December 31, 2017 compared to 2016

Cash generated from operations for the year ended December 31, 2017 increased by ~~$43.9~~$242.8 million compared to the same period in 2014. The decrease in cash flow was primarily the result of a $66.5 million increase in accounts receivable and unbilled revenue in 2015 compared to a decrease of $153.6 million in 2014. This was partially offset by a $60.7 million increase in cash flow related to the PGA rate increase, a $74.5 million reduction in regulatory asset and liability cash outflows and a $36.6 million increase in deferred income taxes and tax credits.

~~Puget Energy~~

~~Cash generated from operations for the year ended December 31, 2015 decreased by $53.1 million compared to the same period in 2014.~~2016. The net ~~decrease~~difference was primarily impacted by the ~~$43.9 million decrease~~increase from cash flow provided by the operating activities of PSE, as previously discussed. The ~~above decrease was also negatively impacted by Puget Energy's $8.3~~remaining variance is explained below:

Non-cash items increased $83.6 million primarily due to changes in deferred taxes of $78.8 million. For further discussion, see Note 13, "Income Taxes" in Item 8.

Changes in cash ~~outflow~~flow resulting from working capital decreased $33.2 million primarily due to amounts owed to PSE related to ~~financing derivatives.~~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 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.

~~As of December 31, 2015 and 2014, PSE had $159.0 million and $85.0 million in short-term debt outstanding, respectively, exclusive of the $28.9 million demand promissory note with~~For information on Puget Energy ~~which was repaid in June 2015. Outside of the consolidation of PSE’s short-term~~and PSE dividends, long-term debt ~~Puget Energy had no short-term debt outstanding in either year as borrowings under its~~and credit facilities, ~~are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees~~see Note 4, “Dividend Payment Restrictions, Note 6, “Long-term Debt” and Note 7, “Liquidity Facilities and Other Financing Arrangements” to the ~~amortization~~consolidated financial statements included in Item 8 of ~~debt issuance costs, during 2015 and 2014 was 4.24%, and 4.05%, respectively. As of December 31, 2015, PSE and Puget Energy had several committed credit facilities that are described below.~~this report.

~~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 $1.450 billion. These unsecured revolving credit facilities expire 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 December 31, 2015, 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 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 December 31, 2015, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $159.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

~~Demand Promissory Note.~~ In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

Debt Restrictive ~~Covenants.~~ 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 December 31, ~~2015,~~2017, PSE could issue:

Approximately ~~$2.4~~$2.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$4.0~~$4.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, ~~2015;~~2017; and

Approximately ~~$434.0~~$535.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately ~~$723.3~~$891.7 million of natural gas bondable property available for issuance, subject to a combined natural gas and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at December 31, ~~2015.~~2017

At December 31, ~~2015,~~2017, PSE had approximately ~~$6.9~~$7.2 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

~~Shelf Registrations and Long-Term Debt Activity.~~ PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $375.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The Company remains subject to the restrictions of PSE’s indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.

On May 26, 2015, PSE issued $425.0 million of senior secured notes. The notes mature in May 2045 and have an interest rate of 4.30%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company’s $150.0 million 5.197% senior notes maturing in October 2015 and the Company’s $250.0 million 6.75% senior notes maturing in January 2016.

~~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 December 31, 2015, approximately $464.1 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 EBITDA to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2015 and the EBITDA to interest expense was 4.9 to one for the 12 months then ended December 31, 2015.

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

~~Puget Energy~~

~~Credit Facility.~~ At December 31, 2015, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which expires 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 December 31, 2015, there was no amount 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% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt (see Part II Item 7A "Interest Rate Risk" section).

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 December 31, 2015, Puget Energy was in compliance with all applicable covenants.

~~Long-Term Debt Activity.~~ In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equaled $299.0 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allowed the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreements, with the exception of maturity and price.

On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes will mature in May 2025 and have an interest rate of 3.65%, which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay all amounts outstanding under Puget Energy's three term loans, and to fund a special dividend to shareholders of approximately $96.7 million. On November 6, 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same amount.

~~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 to one. Puget Energy's EBITDA to interest expense was 3.4 to one for the 12 months then ended December 31, 2015.

~~At December 31, 2015, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.~~

~~OTHER~~

Other

Critical Accounting Policies ~~And~~and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. ~~The~~Management believes the following accounting policies ~~represent those that management believes~~ are particularly important to the financial statements and ~~that~~ require the use of estimates, assumptions and judgment to describe matters that are inherently uncertain.

Revenue ~~Recognition.~~ Recognition

Operating utility revenue is recognized when the basis of service is rendered, which includes estimated unbilled revenue. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed during the month less unbilled revenues recorded in the prior month. The "current" month unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.

Beginning July 1, 2013, certain revenues from PSE's electric and natural gas operations are subject to a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue due to weather and gross margin erosion related to energy efficiency. Any differences are deferred to a regulatory asset for under recovery or a regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism.

As defined by Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980), the decoupling mechanism is an alternative revenue program that allows billings to be adjusted for the effects of weather abnormalities, conservation efforts or other various external factors. PSE adjusts these billings in the future in response to these effects to collect additional revenues provided under the decoupling mechanism. Once billing of additional revenues under the decoupling mechanism is permitted,

the additional revenue can be recognized when the following criteria specified by ASC 980 are met: (i) the program is established by an order from the ~~WUTC~~Washington Commission that allows for automatic adjustment of future rates, (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized. PSE meets the criteria to recognize revenue under the decoupling mechanism. ~~However, if the excess amount cannot be collected within 24 months, for GAAP purposes only, the~~The Company will not record any decoupling revenue ~~unless it~~that is ~~within the~~expected to take longer than 24 months to collect following the end of ~~collection, but will collect~~the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recorded amounts ~~when actually billed.~~will be recorded.

Regulatory ~~Accounting.~~ Accounting

As a regulated entity of the Washington Commission and FERC, PSE prepares its financial statements in accordance with the provisions of ASC 980. The application of ASC 980 results in differences in the timing and recognition of certain revenue and expenses in comparison with businesses in other industries. The rates that are charged by PSE to its customers are based on cost base regulation reviewed and approved by the Washington Commission and FERC. Under the authority of these commissions, PSE has recorded certain regulatory assets and liabilities at December 31, ~~2015~~2017 in the amount of ~~$971.5~~$953.1 million and ~~$663.7~~$1,758.6 million, respectively, and regulatory assets and liabilities at December 31, ~~2014~~2016 of ~~$987.4 million~~$1.1 billion and ~~$635.4~~$653.3 million, respectively. Such amounts are amortized through a corresponding liability or asset account, respectively, with no impact to earnings. PSE expects to fully recover its regulatory assets and liabilities through its rates. If future recovery of costs ceases to be probable, PSE would be required to write off these regulatory assets and liabilities. In addition, if PSE determines that it no longer meets the criteria for continued application of ASC 980, PSE could be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements.

Also encompassed by regulatory accounting and subject to ASC 980 are the PCA and PGA mechanisms. The PCA and PGA mechanisms mitigate the impact of commodity price volatility upon the Company and are approved by the Washington Commission. The PCA mechanism provides for a sharing of costs that vary from baseline rates over a graduated scale. For further discussion regarding the PCA mechanism, see ~~Electric Regulation and Rates within~~ Item ~~1. Business~~7, "Business – Regulation and ~~Rates of this report.~~Rates". The increases and decreases in the cost of natural gas supply are reflected in ~~customers'~~customer bills through the PGA

mechanism. PSE expects to fully ~~recover~~recover/refund these regulatory ~~assets~~balances through its rates. However, both mechanisms are subject to regulatory review and approval by the Washington Commission on a periodic basis.

~~Goodwill.~~Goodwill

In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles - Goodwill and Other,” (ASC 350) requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit.

The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a ~~two-step process. The~~qualitative and quantitative test. Management must first ~~step compares~~assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines the fair value of a reporting unit ~~with~~is less than its ~~fair value, with~~carrying amount, then the entity shall perform a ~~carrying value higher than fair value indicating potential~~quantitative test to determine impairment. ~~If the first step test fails, the second step is performed.~~ This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount.

Puget Energy conducted its most recent annual impairment test as of October 1, ~~2015~~.2017. The fair value of Puget Energy’s reporting unit was estimated using the weighted-averages from an income valuation method, or discounted cash flow method, and a market valuation approach. These valuations required significant judgments, including: ~~(1)~~(i) estimation of future cash flows, which is dependent on internal forecasts ~~(2)~~and other market factors, (ii) estimation of the long-term rate of growth for Puget Energy’s business ~~(3)~~including other market factors, (iii) estimation of the useful life over which cash flows will occur, ~~(4)~~(iv) the selection of utility holding companies determined to be comparable to Puget Energy, and ~~(5)~~(v) the determination of an appropriate weighted-average cost of capital or discount rate.

Management estimated the fair value of Puget Energy’s equity to be approximately ~~$4.6~~$5.5 billion at the October 1, ~~2015~~2017 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately ~~$3.5~~$3.8 billion with the excess of the fair value over the carrying value representing ~~30.9%~~44.7% or ~~$1.1~~$1.7 billion.

The income approach and the market approach valuations resulted in Puget Energy equity values of ~~$4.7 billion~~$5.2 and ~~$4.4~~$5.8 billion, respectively. The result of the income approach was very sensitive to long-term cash flow growth rates applicable to periods beyond management’s five-year business plan and financial forecast period and the weighted-average cost of capital assumptions of ~~2.7%~~3.0% and ~~6.5%~~5.9%, respectively.

The following table summarizes the results of the income valuation ~~method:~~method, using the long-term growth rate and weighted average cost of capital:


Equity Value Sensitivity Table
(Dollars in Billions)
Weighted-Average Cost of Capital Rate	Long-Term Growth Rate																		Long-Term Growth Rate
	2.5		%	2.6		%	2.7		%	2.8		%	2.9		%	3.0		%	2.8		%	2.9		%	3.0		%	3.1		%	3.2		%	��	3.3		%
6.8%	$	3.5		$	3.7		$	3.9		$	4.2		$	4.4		$	4.7
6.5	4.2			4.4			4.7			5.0			5.3			5.6
6.3	5.0			5.2			5.5			5.9			6.2			6.6
6.2%																			$	3.7		$	4.0		$	4.3		$	4.6		$	4.9			$	5.3
5.9																			4.5			4.9			5.2			5.6			6.0				6.5
5.7																			5.6			6.0			6.4			6.9			7.4				7.9

Fuel and Natural Gas Inventory

Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and liquefied natural gas (LNG) held in storage for future sales. ~~Puget Energy and PSE record~~The Company records these items at the lower of cost or ~~market~~net realizable value ~~using the weighted-average cost~~ method.

Regulatory Assets and Liabilities

PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains ~~and losses~~ that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term ~~due to the length of the amortization.~~when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 3.3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts.

Allowance for Funds Used During Construction

AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility ~~plant and~~plant; the AFUDC debt portion is credited to interest expense, ~~and as a non-cash item~~while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates.

The current AFUDC ~~rates~~rate authorized by the Washington Commission for natural gas and electric utility plant additions ~~are based on~~through December 18, 2017 was 7.77%. Effective December 19, 2017 with the ~~effective dates as follows:~~Washington Commission order, the new AFUDC rate authorized is 7.60%.



~~Effective Date~~	~~Washington Commission~~ ~~AFUDC Rates~~
~~July 1, 2013 - present~~	~~7.77~~	%
~~May 14, 2012 - June 30, 2013~~	~~7.80~~

The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 ~~years~~.years.

Revenue Recognition

Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer.

PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $257.1 million, $235.3 million and $234.2 million for 2017, 2016 and 2015, respectively. The ~~non-utility subsidiary recognizes~~Company reports the collection of such taxes on a gross basis in operation revenue ~~when services are performed or upon~~and as expense in taxes other than income taxes in the ~~sale~~accompanying consolidated statements of ~~assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits (RECs) are deferred as a regulatory liability.~~income.

PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue ~~due to weather~~ and gross margin erosion ~~related~~due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. ~~To record revenues~~Revenue is recognized under this program ~~the Company must be able to collect the revenue~~when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. IfOn December 5, 2017, the ~~excess~~Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount ~~cannot be collected within 24 months,~~of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for ~~GAAP purposes only, the~~ natural gas customers but will remain at 3.0% for electric customers. The

Company will not

record any decoupling revenue ~~unless it~~that is ~~within the~~expected to take longer than 24 months to collect following the end of ~~collection, but~~the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will ~~collect non-recorded amounts when actually billed.~~be recognized. Revenues associated with energy costs under the ~~Power Cost Adjustment~~power cost adjustment (PCA) mechanism and ~~Purchased Gas Adjustment~~purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism.

Allowance for Doubtful Accounts

Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off.

The Company’s balance for allowance for doubtful accounts at December 31, ~~2015~~2017 and ~~2014~~2016 was $8.9 million and $9.8 million, ~~and $7.5 million,~~ respectively.

Self-Insurance

PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. ~~The~~Under the December 5, 2017 Washington Commission ~~has approved~~order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of ~~certain uninsured qualifying storm damage costs that exceed~~ ~~$8.0~~storms under the mechanism increased from $8.0 million ~~which will be requested for collection in future rates.~~ to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.

Federal Income Taxes

For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, ~~who~~which is the ultimate tax payer.

Natural Gas Off-System Sales and Capacity Release

PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.

~~Non-Core Natural Gas Sales~~

As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in ~~other~~ electric operating revenue and are included in the PCA mechanism.

Production Tax Credit

Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable ~~sources.~~sources during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE ~~records~~to its customers when monetized on the ~~benefit~~income tax return through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense was also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs ~~as a regulatory liability until such time as PSE utilizes~~to fund the ~~tax credit on its tax return. Once utilized, PSE~~following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will ~~pass the benefit to customers.~~no longer be

refunded to customers through the revenue requirement, a non-cash charge to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 $2.1 million of PTCs are estimated to be monetized through tax filings.

Accounting for Derivatives

ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the ~~Normal Purchase Normal Sale~~normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for ~~energy~~natural gas related derivatives due to the ~~PCA mechanism and~~ PGA mechanism.

Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial ~~reporting in 2009.~~reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (AOCI) is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs.

The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, ~~2015~~,2017, Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9, ~~Accounting~~ "Accounting for Derivative Instruments and Hedging ~~Activities.~~Activities" to the consolidated financial statements included in Item 8 of this report.

Fair Value Measurements of Derivatives

ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 ~~Fair~~, "Fair Value ~~Measurements.~~Measurements" to the consolidated financial statements included in Item 8 of this report.

Debt Related Costs

Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for ~~PSE.~~PSE and presented net of long-term liabilities on the balance sheet.

(2) New Accounting Pronouncements

Revenue Recognition

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

The standard is effective for the Company beginning January 1, 2018 and allows for two methods of adoption: application of the standard to each prior reporting period presented (full retrospective), or application of a cumulative effect on retained earnings recognized at the date of initial application (modified retrospective method). The Company will adopt the standard using the modified retrospective method. In preparation for adoption of the standard, the Company initiated a project team that met bi-weekly to make key accounting assessments related to the standard, which included the implementation of associated internal controls.

As a result of implementation of this standard, the Company has concluded there to be no impact on revenue for contracts with customers open as of January 1, 2018. The Company's revenue is 93.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue will continue to be recognized over time as delivered. Pursuant to the new standard, the Company's current presentation of revenue on the income statement will not change; however, enhanced disclosure for revenue from contracts with customers and revenue outside the scope of ASC 606 will be disclosed.

Lease Accounting

In ~~August 2015,~~February 2016, the FASB issued ASU ~~2015-14,~~ 2016-02, "Leases (Topic 842)"~~Revenue~~. The FASB issued this ASU and the related amendments to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. ASU 2016-02requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from ~~Contracts with Customers (Topic 606): Deferral~~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 ~~Effective Date,"~~ ~~deferring~~lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged.

This amendment is effective ~~date~~ for ~~ASU 2014-09 to fiscal years, and interim periods within those~~financial statements issued for fiscal years beginning after December 15, ~~2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and~~2018, including interim periods within those fiscal ~~years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 according to the original effective date.~~years. Earlier adoption is permitted for all entities upon issuance. Reporting entities ~~also have the option of using either a full retrospective or~~must apply a modified retrospective approach for the adoption of the new standard. The Company ~~initiated~~will adopt ASU 2016-02 during the first quarter of fiscal year 2019. The Company expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a ~~steering committee~~material impact on the consolidated balance sheets. For a current breakout of existing operating and ~~project team~~capital leases, see Note 8, "Leases" to ~~evaluate~~ the ~~impact~~consolidated financial statements included in Item 8 of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements.report.

~~Debt Issuance Costs~~Statement of Cash Flows

In ~~April 2015,~~August 2016, the FASB issued ASU ~~2015-03,~~2016-15, "~~Interest-Imputation~~Statement of ~~Interest (Subtopic 835-30)~~Cash Flows (Topic 230): ~~Simplifying the Presentation~~Classification of ~~Debt Issuance Costs.~~Certain Cash Receipts and Cash Payments". The amendments in ASU ~~2015-03 requires~~2016-15 provide guidance for eight specific cash flow issues that include (i) debt ~~issuance~~prepayment or debt extinguishment costs, ~~related to~~(ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a ~~recognized debt liability be presented in the balance sheet as a direct deduction~~business combination, (iv) proceeds from the ~~carrying amount~~settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the debt liability, consistent with the presentation of a debt discount. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.predominance principle.

~~In August 2015, the FASB issued ASU 2015-15, "Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement~~." In accordance with the United States Securities and Exchange Commission (SEC) Staff Announcement at the June 18, 2015 Emerging Issues Task Force (EITF) meeting about debt issuance costs, ASU 2015-15 amended the accounting guidance updated by ASU 2015-03 to allow reporting entities the option to defer and present debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement.

~~ASU 2015-03 and ASU 2015-15 are~~This update is effective for financial statements issued for fiscal years beginning after December 15, ~~2015,~~2017, and interim periods within those fiscal years. Early adoption ~~of the amendments~~ is permitted for ~~financial statements that have not been previously issued.~~all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company ~~plans to~~will adopt ASU 2016-15 during the ~~amendments during~~first quarter of fiscal year 2016. The amount of unamortized debt issuance costs at Puget Energy as of December 31, 2015 and 2014 totaled $38.4 million and $35.7 million, respectively. The amount of unamortized debt issuance costs at PSE as of December 31, 2015 and 2014 totaled $30.0 million and $28.7 million, respectively.

~~Internal-Use Software~~

~~In April 2015, the FASB issued ASU 2015-05, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement.~~" ASU 2015-05 requires a customer in a cloud computing arrangement to follow internal-use software guidance if both of the following criteria are met: the customer has the contractual right to take possession of the software at any time during the cloud computing arrangement and can feasibly run the software on its own hardware. If the customer does not meet both criteria, the cloud computing arrangement is considered a service contract and separate accounting for a license would not be permitted.

ASU 2015-05 is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2015. Early adoption is permitted. The Company plans to adopt ASU 2015-05 during fiscal year 20162018 and is in the process of evaluating ~~the potential impacts, if any, of this new guidance on its financial statements.~~

~~Fair Value Measurement~~

~~In May 2015, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)~~," which removes the requirement to categorize within the fair value hierarchy all investments for which their fair value is measured using the net asset value per share practical expedient. This ASU also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, those disclosures will be limited to investments for which the Company has elected to measure the fair value using that practical expedient.

ASU 2015-07 is effective for annual reporting periods, and interim periods within those reporting periods, beginning after December 15, 2015, and requires reporting entities to apply this ASU retrospectively to all periods presented. Early adoption is permitted. The Company plans to adopt ASU 2015-07 during fiscal year 2016. At this time, the Company cannot determine the impact this standard will have on its consolidated ~~financial statements.~~

~~Inventory~~statement of cash flows.

In ~~July 2015,~~November 2016, the FASB issued ASU ~~2015-11,~~2016-18, "~~Inventory~~Statement of Cash Flows (Topic ~~330)~~230): ~~Simplifying the Measurement of Inventory.~~Restricted Cash" ~~ASU 2015-11 requires inventory within~~. The amendments in this update require that a statement of cash flows explain the ~~scope~~change during the period in the total of this Topic 330 to be measured at the lower of cost and net realizable value. This amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. This amendment applies to all other inventory, including inventory measured using first-in, first-out (FIFO) or average cost.cash, cash equivalents,

and amounts generally described as restricted cash or restricted cash equivalents. The new ~~accounting guidance~~standard is effective for ~~annual reporting periods,~~fiscal years beginning after December 15, 2017, and interim periods within those ~~annual reporting periods, beginning after December 15, 2016, with early adoption permitted.~~fiscal years. The Company ~~plans to~~will adopt ASU ~~2015-11~~2016-18 during the first quarter of fiscal year ~~2017. At this time,~~2018 retrospectively to all periods presented by moving the presentation of restricted cash, in the statement of cash flows, to net cash flows of total cash, cash equivalents, and restricted cash. Additionally, the Company ~~cannot determine~~will disclose the ~~impact this standard will have on its consolidated financial statements.~~nature of the Company's restricted cash.

Retirement Benefits

In ~~July 2015,~~March 2017, the FASB issued ASU ~~2015-12,~~2017-07, "~~Plan Accounting: Defined~~Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit ~~Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962),~~Cost". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and ~~Health~~actuarial gains and ~~Welfare Benefit Plans (Topic 965).~~" ASU 2015-12 is made up of three parts: Part I, Fully Benefit-Responsive Investment Contracts (Part I); Part II, Plan Investment Disclosures (Part II); and Part III, Measurement Date Practical Expedient (Part III).

~~Part I requires fully benefit-responsive contracts~~losses) are required to be ~~measured,~~ presented in the income statement separately from the service cost component and ~~disclosed~~outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only at contract value. Part II requires both participant-directed and nonparticipant-directed investments of employee benefit plans be grouped only by general type, and removes the requirement to include the disclosure of (i) the investment strategy of an investment measured using the net asset value per share practical expedient andeligible cost for capitalization.

This amendment is part of a fund that files a U.S. Department of Labor Form 5500; and (ii) the net appreciation or depreciation for investments by general type. Part III provides entities that have a fiscal year-end that does not coincide with a month-end a practical expedient to permit plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan's fiscal year-end.

~~All three parts are~~ effective for fiscal years beginning after December 15, ~~2015, and early~~2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for ~~each part. Parts I and II must be applied retrospectively for all~~which financial statements ~~presented.~~(interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments ~~in Part III must be applied~~related to income statement activity retrospectively, and balance sheet activity prospectively. The ~~Company plans to adopt ASU 2015-12 during~~Company’s non-service components for the ~~fiscal~~ year ~~2016,~~ended December 31, 2017, was a credit of $18.4 million for Puget Energy and is$4.7 million for PSE. The non-service cost components are in an income position and will be presented in the ~~process of evaluating the potential impacts, if any, of this new guidance on its financial statements.~~other income section, upon adoption.

~~Derivatives and Hedging~~Stranded Tax Effects in AOCI

In ~~August 2015, the FASB Issues ASU 2015-13, "Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets.~~" ASU 2015-13 allows certain reporting entities that enter into derivative contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through a nodal energy market, to designate those contracts as normal purchase or normal sale contracts, if the physical delivery criterion is met. This designation removes the ASC 815, Derivatives and Hedging (ASC 815), requirement to measure those derivative contracts at fair value.

This amendment was effective upon issuance, and if elected, the guidance must be applied prospectively. The Company does not expect this guidance to have a material impact on its results of operations or financial position.

~~Deferred Income Taxes~~

~~In November 2015,~~February 2018, the FASB issued ASU ~~2015-17,~~2018-02, "Income ~~Taxes~~Statement—Reporting Comprehensive Income (Topic ~~740)~~220): ~~Balance Sheet Classification~~Reclassification of ~~Deferred Taxes.~~Certain Tax Effects from Accumulated Other Comprehensive Income" ~~ASU 2015-17 requires reporting entities~~. The amendments in this update allow reclassification from accumulated other comprehensive income to ~~classify deferred~~retained earnings for stranded tax ~~liabilities~~effects resulting from the Tax Cuts and ~~assets as noncurrent in a classified balance sheet instead~~Jobs Act (TCJA) and will improve the usefulness of ~~separating such deferred taxes into current and noncurrent amounts.~~information reported to financial statement users.

This amendment is effective for ~~financial statements issued for annual periods~~fiscal years beginning after December 15, ~~2016, and~~2018, including interim periods within those ~~annual periods. Earlier~~years. Early adoption is permitted, ~~for all entities as of the beginning of~~including adoption in any interim ~~or annual~~period for reporting ~~period.~~periods for which financial statements have not yet been issued. The Company ~~has~~will early ~~adopted~~adopt ASU ~~2015-17 for~~2018-02 during the ~~annual reporting period ended December 31, 2015, and has applied this amendment retrospectively. Except for changes in Consolidated Balance Sheet presentation, this guidance does~~

~~not have~~first quarter of fiscal year 2018 through a ~~material impact on the Company's results of operations or financial position. For additional information on~~retrospective reclassification from accumulated other comprehensive income to retained earnings. The Company is still evaluating the impact of ~~this guidance, see Note 13, Income Taxes.~~the reclassification to retained earnings.

(3) Regulation and Rates

Regulatory Assets and Liabilities

Regulatory accounting allows PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future.

~~Below is a table with the allowed return on the net regulatory assets and liabilities and the associated time periods:~~

Period Rate of Return After-Tax Return
July 1, 2013 - present 7.77 % 6.69 %
May 14, 2012 - June 30, 2013 7.80
6.71

The net regulatory assets and liabilities at December 31, ~~2015~~2017 and ~~2014~~2016 included the following:


Puget Sound Energy	Remaining Amortization Period	December 31,									Remaining Amortization Period		December 31,
(Dollars in Thousands)		2015					2014					2017						2016
Storm damage costs electric	1 to 3 years			$	125,777			$	118,824			4 to 6 years				128,508						122,709
Colstrip 1 & 2 Regulatory Asset											N/A				127,627						176,804
Decoupling deferrals and interest													98,769						156,408
Decoupling 24-month revenue reserve													—						(20,847	)
Total decoupling asset											Less than 2 years				98,769						135,561
Chelan PUD contract initiation	15.8 Years			112,228				119,316			13.8 years				98,052						105,140
Deferred decoupling revenue		104,150					55,363
Decoupling revenue in excess of 2 years		(9,980	)				—
Total deferred decoupling revenue	Less than 2 years			94,170				55,363
Environmental remediation											(a)				81,550						74,557
Lower Snake River	1 to 21.3 years			79,599				86,275			19.4 years				70,975						74,862
Deferred income taxes	(a)			72,694				94,913
Environmental remediation	(a)			66,887				66,018
Baker Dam licensing operating and maintenance costs	43 years			63,394				61,577			N/A				54,817						61,453
PGA deferral of unrealized losses on derivative instruments	(a)			60,889				69,280
Deferred Washington Commission AFUDC	35 years			52,197				53,709			10 years				50,301						51,404
Unamortized loss on reacquired debt	1 to 20.5 years			44,984				35,667			1 to 28 years				39,674						42,196
Property tax tracker	Less than 2 years			40,353				32,253			Less than 2 years				36,517						41,949
Energy conservation costs	1 to 2 years			36,646				42,374			(a)				35,538						41,027
PGA deferral of unrealized losses on derivative instruments											N/A				26,030						—
White River relicensing and other costs	16.9 years			23,054				26,685			3 years				19,502						21,627
Generation plant major maintenance, excluding Colstrip											5 to 11 years				17,216						13,178
Mint Farm ownership and operating costs	9.3 years			18,320				20,320			7.3 years				14,319						16,319
Colstrip major maintenance											1.5 years				8,723						6,589
Snoqualmie licensing operating and maintenance costs											N/A				7,341						8,018
Ferndale	3.8 years			15,253				19,232			1.8 years				7,295						11,274
Colstrip common property											7.4 years				4,618						5,334
PCA mechanism											N/A				4,576						4,531
Electron unrecovered loss	3 years			10,569				14,008			1 year				3,786						7,178
Snoqualmie licensing operating and maintenance costs	29 years			7,980				9,202
Colstrip common property	8.5 years			6,049				6,764
Colstrip major maintenance	2 years			5,897				2,712
Investment in Bonneville Exchange power contract	1.5 years			5,290				8,816
Snoqualmie	2.8 years			5,024				6,798
Deferred income taxes^(d)											N/A				—						71,517
PGA receivable	1 year			—				21,073			1 year				—						2,785
Various other regulatory assets	Varies			24,248				16,223			(a)				17,382						17,173
Total PSE regulatory assets				$	971,502			$	987,402						953,116						1,113,185
Deferred income taxes^(d)											N/A				(1,012,260		)				—
Cost of removal	(b)			$	(347,472	)		$	(313,088	)	(b)				(389,579		)				(369,300		)
Treasury grants	4 to 43 years			(157,102		)		(180,496		)	20 years				(205,775		)				(133,709		)
Production tax credits	(c)			(93,616		)		(93,616		)	(c)				(93,616		)				(93,616		)
Decoupling over-collection	Less than 2 years			(25,483		)		(12,582		)
Decoupling ROR excess earnings													(18,400	)					(13,300	)
Decoupling deferrals and interest													(7,896	)					(16,448	)
Total decoupling liability											Less than 2 years				(26,296		)				(29,748		)
PGA payable	1 year			(12,589		)		—			1 year				(16,051		)				—
Summit purchase option buy-out	4.8 years			(7,612		)		(9,188		)	2.8 years				(4,463		)				(6,038		)
Deferral of treasury grant amortization	Less than 4 years			(6,058		)		(8,197		)
PGA deferral of unrealized gains on derivative instruments											N/A				—						(7,517		)
Various other regulatory liabilities	Up to 4 years			(13,751		)		(18,215		)	(a)				(10,544		)				(13,368		)
Total PSE regulatory liabilities				$	(663,683	)		$	(635,382	)					(1,758,584		)				(653,296		)
PSE net regulatory assets (liabilities)				$	307,819			$	352,020						$	(805,468	)				$	459,889

_______________


^(a)	Amortization periods vary depending on timing of underlying ~~transactions or awaiting regulatory approval in a future Washington Commission rate proceeding.~~transactions.


^(b)	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.


^(c)	Amortization will begin once PTCs are utilized by PSE on its tax return.


^(d)	For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.


Puget Energy	Remaining Amortization Period	December 31,						Remaining Amortization Period		December 31,
(Dollars in Thousands)	Remaining Amortization Period	2015			2014				2017				2016
Total PSE regulatory assets	(a)	$	971,502		$	987,402		Remaining Amortization Period	(a)		$	953,116			$	1,113,185
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	1 to 21 years	26,223			29,816			1 to 20 years		19,454				22,613
Various other regulatory assets	Varies	549			561			Varies		(8		)		517
Total Puget Energy regulatory assets		$	998,274		$	1,017,779				972,562				1,136,315
Total PSE regulatory liabilities	(a)	$	(663,683	)	$	(635,382	)	(a)		(1,758,584		)		(653,296		)
Puget Energy acquisition adjustments:
Deferred income taxes										634				—
Regulatory liabilities related to power contracts	1 to 36 years	(325,788		)	(391,389		)	1 to 35 years		(174,918		)		(275,061		)
Various other regulatory liabilities	Varies	(1,347		)	(2,820		)	Varies		(1,314		)		(1,326		)
Total Puget Energy regulatory liabilities		$	(990,818	)	$	(1,029,591	)			(1,934,182		)		(929,683		)
Puget Energy net regulatory asset (liabilities)		$	7,456		$	(11,812	)			$	(961,620	)		$	206,632

_______________


^(a)	Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.

If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write-off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the ~~Company’s~~Company's financial statements.

In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability ~~$347.5~~$389.6 million and $~~313.1~~369.3 million in ~~2015~~2017 and ~~2014~~2016, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates.

~~2013 Expedited~~General Rate Case Filing ~~Decoupling and Centralia Decision~~

On January 13, 2017, PSE filed ~~a settlement agreement~~its GRC with the Washington Commission, ~~on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the expedited rate filing (ERF)~~ which is limited in scope and rate impact, includes the property tax tracker, and is intended to establish baseline rates on which the decoupling mechanism are to operate. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule.

On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to7.77% to update long term debt costs. 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 rate plan increase allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next GRC which will be filed before April 1, 2016. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. Order No. 8 in the TransAlta Centralia proceeding granted in part and denied in part PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order regarding TransAlta Centralia.

On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties' petition argued that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a letter decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. The remand proceeding evidentiary hearings regarding return on equity (ROE) were held in February 2015 and initial briefs and reply briefs were filed in March 2015. The Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable ROE for PSE for the term of the rate plan, taking decoupling and other relevant factors into account.

~~Expedited Rate Filing~~

On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and ERF tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for electric and natural gas customers is an increase of $21.4 million, or 1.0%, annually and an increase of $10.8 million, or 1.1% annually, respectively. The estimated revenue impact of the ERF filings for electric and natural gas customers is an increase of $30.7 million, or 1.5%, annually and a decrease of $2.0 million, or a decrease of 0.2% annually, respectively. In its order, the Washington Commission approvedproposed a weighted cost of capital of ~~7.77%~~7.74%, or 6.69% after-tax, and a capital structure ~~that included 48.0%~~of 48.5% in common equity with a ~~ROE~~return on equity of 9.8%. ~~Subsequently, certain~~The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1%, annually. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million, or 2.4%, annually. Additionally, a depreciation study which calculates annual depreciation accruals related to utility plant was filed as part of the GRC filing. The tariffs were subsequently suspended, which means that the final rates authorized in the proceeding would go into effect on or shortly after the suspension date of 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 Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contained requests for two new mechanisms to address regulatory lag. PSE requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties to ~~this~~the proceeding, ~~petitioned~~including PSE, filed a multi-party settlement agreement with the Washington ~~Commission to reconsider~~Commission. The multi-party settlement resolved some, but not all, contested issues in the ~~order. On December 13, 2013,~~case. Hearings were held on August 30, 2017 regarding the ~~Washington Commission approved~~contested issues and on September 29, 2017 regarding the multi-party settlement. The settlement ~~agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013.~~

~~On February 4, 2013, PSE filed revised tariffs in an ERF proceeding seeking to update the rates set~~agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. The settlement agreement resolved all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%.

The expected closure date for Colstrip Units 1 and 2 is July 1, 2022 and the settlement included a plan to cover the costs for the closure of these Units. As part of the settlement PSE committed to fund a Colstrip Community Transition Fund of $10.0 million of which PSE shareholders will fund $5.0 million and $5.0 million will be funded by the regulatory liability for monetized PTCs, which are PTCs used on the filed tax returns. PSE is recognizing the funding of this commitment at the time the PTC’s are accrued for use in the ~~final order of May 2012 in PSE's general rate case (GRC). This ERF filing was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which~~tax return. The settlement provided that the ~~decoupling mechanisms, described below, were proposed to operate. The filing also provided~~regulatory liability for monetized PTCs will be used for the ~~collection~~following Colstrip costs: (i) Colstrip Community Transition Fund, (ii) recover unrecovered Colstrip plant and (iii) recover incurred decommissioning and remediation costs for Colstrip. In addition, the hydro-related treasury grants were allowed to be used to fund and recover incurred decommissioning and remediation costs for Colstrip 1 and 2 as established in RCW 80.04.350. Depreciation rates were updated which increased PSE's depreciation for Colstrip Units 1 and 2. The increase in depreciation caused the Colstrip regulatory asset to be reduced to $127.6 million as of ~~property taxes through a property tax tracker mechanism~~December 31, 2017. Finally, depreciation rates for Colstrip Units 3 and 4 were also updated, which increased PSE's depreciation to recover plant costs for those units based on ~~cash payments~~a negotiated depreciation life ending on December 31, 2027.

The contested issues were PSE’s proposed electric CRM, the majority of ~~property tax made by PSE during~~decoupling issues, certain portions of electric rate spread/rate design issues and the ~~year. Any difference between~~entire natural gas rate spread/rate design-related issues. The Washington Commission also ruled on the ~~cash payments~~remaining contested issues on December 5, 2017. The Washington Commission approved, PSE's proposal to modify its earning sharing mechanism to exclude normalizing adjustments that are required for Commission Basis Reporting purposes under Washington Administrative Code 480-90-257 (natural gas) and ~~property tax accruals will be deferred and recovered in a property tax tracker.~~480-100-257 (electric). The Washington Commission rejected PSE’s requested electric CRM.

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

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will end on ~~February 28, 2017~~the effective date of PSE’s first rate case or other proceeding filed in or after 2021 unless the continuation of the mechanism is approved in either of those proceedings. PSE’s ~~next GRC filing which~~decoupling mechanism over and under collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

There is a 3.0% cap for electric and 5.0% cap for natural gas on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet, PSE ~~is required~~performed an analysis as of December 31, 2017 to ~~file by April 1, 2016 at the latest.~~

~~On April 22, 2015, the Washington Commission approved PSE's request to change rates under its~~determine if electric and natural gas decoupling ~~mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling~~revenue deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculationwould be collected from customers within 24 months of the ~~current year~~annual period, per ASC 980-605. If not, for GAAP purposes only, PSE will need to record a reserve against the decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6%, annually, and a rate increase for natural gas customers of $22.0 million, or 2.1%, annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the 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 certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and ~~$8.2 million~~regulatory asset balance. Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all current deferred revenues for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

~~On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its~~ electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $10.6 million, or 0.5% annually, and a rate decrease for natural gas customers of $1.0 million, or 0.1% annually.

On December 13, 2013, the Washington Commission approved a series of settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism and will be ~~subject~~collected within 24 months of the annual period; therefore, there were no adjustments to ~~certain effects~~2017 decoupling revenues other than to record the previously unrecognized decoupling deferrals of ~~abnormal weather, conservation impacts and changes in customer usage patterns.~~$20.8 million.

~~Electric Regulation and Rates~~

Storm Damage Deferral Accounting

The Washington Commission issued a GRC order that defined deferrable ~~catastrophic/extraordinary losses~~storm events and provided that costs in excess of ~~$8.0 million~~ ~~annually~~the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In ~~2015~~2017 and ~~2014~~,2016, PSE incurred ~~$33.6~~$30.4 million and ~~$29.7~~$22.0 million,, respectively, in storm-related electric transmission and distribution system restoration costs, of which ~~$22.4~~$21.6 million was deferred in ~~2015~~2017 and ~~$18.0~~$12.4 million was deferred in ~~2014~~.2016. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than$0.5 million will not qualify for deferral and these costs will also not count toward the 10.0 million annual cost threshold.

~~Power Cost Only Rate Case~~Washington Commission Tax Deferral Filing

~~A limited-scope proceeding~~The TCJA was ~~approved~~signed into law in ~~2002~~December of 2017. As a result of this change, PSE reviewed its deferred tax balances under the new corporate tax rate. As PSE is a regulated utility, the impact of tax rate changes on the deferred tax balance is subject to approval by the Washington Commission to periodically reset power cost rates. In addition to providing the opportunity to reset all power costs, the power cost only rate case (PCORC) proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC.

~~The following table sets forth PCORC rate adjustments approved by the Washington Commission and the corresponding 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)
December 1, 2014 (0.9 )% $ (19.4 )
November 1, 2013 (0.5 ) (10.5 )

~~Electric Property Tax Tracker Mechanism~~

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May 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 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, 2015 0.4 % $ 8.4
May 1, 2014 0.5
11.0

~~Electric Conservation Rider~~

~~The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding 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, 2014 0.6 % $ 12.2

~~Accounting Orders and Petitions~~

PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to Jefferson County Public Utility District (JPUD) on March 31, 2013. The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million. In accordance with a 2010 Washington Commission order, PSE deferred the gain and recorded it as a regulatory liability pending the Washington Commission's determination of the accounting and ratemaking treatment. On October 31, 2013,Commission. Accordingly, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for ~~a Washington Commission order that would authorize PSE~~the impacts of tax reform. The deferral accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to ~~retain~~ the gain of $45.0 million and return $15.0 million to its remaining customers over a period of 48 months. On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. A final order was rendered on September 11, 2014 which authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was booked to a regulatory liability ~~account in other current liabilities and accrued interest at PSE's after-tax~~for deferred income taxes. The tax rate ~~of return. PSE paid this amount~~change for certain deferred tax balances that are not subject to ~~customers~~regulatory treatment have been recorded through ~~a bill credit in the month of December 2014.~~

~~Power Cost Adjustment Mechanism~~

PSE currently has a PCA mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” included in revenue requirements. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.

~~The graduated scale currently applicable is 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 will not take effect until January 1, 2017. Key components of the settlement will result in the following changes to the PCA mechanism:

Company's Share Customers' Share
Annual Power Cost Variability Over Under Over Under
+/- $17 million 100 % 100 % — % — %
+/- $17 million - $40 million 35
50
65
50
+/- $40+ million 10
10
90
90

~~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 as part of the next 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 on depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, 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 PCORC, and agreeing, 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/PCORC.~~

~~Federal Incentive Tracker Tariff~~

The Federal Incentive tracker tariff passes the benefits associated with treasury grants received by the company and PTCs available through to its customers. 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 Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:~~

~~Gas Regulation and Rates~~

~~Gas General Rate Cases and Other Filings Affecting Rates~~

~~Cost Recovery Mechanism~~

~~The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding 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, 2015 0.5 % $ 5.3
November 1, 2014 0.2
2.3

~~Property Tax Tracker Mechanism~~

~~The purpose of the property~~ tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May 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 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)
June 1, 2015 (0.2 )% $ (2.3 )
May 1, 2014 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 liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.

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

Environmental Remediation

The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the ~~environmental protection agency~~Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review. The Washington Commission consolidated the gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008. PerIn accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of ~~$32.6~~$38.9 million for natural gas and ~~$6.1~~$8.9 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, ~~2015,~~2017, the Company’s share of future remediation costs is estimated to be approximately ~~$23.9~~$28.6 million. The Company's deferred electric environmental costs are ~~$14.0~~$17.6 million, ~~$13.4~~$13.8 million and ~~$12.3~~$14.0 million at December 31, ~~2015, 2014~~2017, 2016 and ~~2013,~~2015, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are ~~$52.9~~$63.9 million, ~~$52.6~~$60.7 million, and ~~$45.1~~$52.9 million at December 31, ~~2015, 2014~~2017, 2016 and ~~2013,~~2015, respectively, net of insurance proceeds. In the GRC which became effective December 19, 2017, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates.

Retirement Plan

Under the Retirement Plan, the Company's eligible employees hired prior to January 1, 2014 (prior to December 12, 2014, in the case of IBEW-represented employees), including the Named Executive Officers, accrue benefits in accordance with a cash balance formula, beginning on the later of their date of hire or March 1, 1997. Under this formula, for each calendar year after 1996, age-weighted pay credits are allocated to a bookkeeping account (a Cash Balance Account) for each participant. The pay credits range from 3% to 8% of eligible compensation. Non-represented and UA-represented employees hired on or after January 1, 2014 and IBEW-represented employees hired on or after December 12, 2014 will receive pay credits equal to 4% (rather than the age-based pay credit described above), which non-represented and IBEW-represented employees may choose to have contributed to the Company’s 401(k) plan, rather than credited under the Retirement Plan. Eligible compensation generally includes base salary and bonuses (other than bonuses paid under the LTI Plan and signing, retention and similar bonuses), up to the limit imposed by the Internal Revenue Code. For ~~2015,~~2017, the limit was ~~$265,000.~~$270,000. For ~~2016,~~2018, the limit is ~~$265,000.~~$275,000. In addition, as of March 1, 1997, the Cash Balance Account of each participant who was participating in the Retirement Plan on March 1, 1997 was credited with an amount based on the actuarial present value of that participant’s accrued benefit, as of February 28, 1997, under the Retirement Plan’s previous formula. Amounts in the Cash Balance Accounts are also credited with interest. The interest crediting rate is 4% per year or such higher amount as PSE may determine. For ~~2015~~2017 and ~~2016,~~2018, the annual interest crediting rate was 4%.

A participant’s Retirement Plan benefit generally vests upon the earlier of the participant’s completion of three years of active service with Puget Energy, PSE or their affiliates or attainment of age 65 (the Retirement Plan’s normal retirement age) while employed by the Company or one of its affiliates. Normal retirement benefit payments begin to a vested participant as of the first day of the month following the later of the participant’s termination of employment or attainment of age 65. However, a vested participant may elect to have his or her benefit under the Retirement Plan paid, or commence to be paid, as of the first day of any month commencing after the date on which his or her employment with Puget Energy, PSE and their affiliates terminates. If benefit payments commence prior to the participant’s attainment of age 65, then the amount of the monthly payments will be reduced for early commencement to reflect the fact that payments will be made over a longer period of time. This reduction is subsidized - that is, it is less than a pure actuarial reduction. The amount of this reduction is, on average, 0.30% for each of the first 60 months, 0.33% for each of the second 60 months, 0.23% for each of the third 60 months and 0.17% for each of the fourth 60 months that the payment commencement date precedes the participant’s 65th birthday. Further reductions apply for each additional month that the payment commencement date precedes the participant’s 65th birthday. As of December 31, ~~2015,~~2017, all the Named Executive Officers were vested in their benefits under the Retirement Plan and, hence, would be eligible to commence benefit payments upon termination.

The normal form of benefit payment for unmarried participants is a straight life annuity providing monthly payments for the remainder of the participant’s life, with no death benefits. The straight life annuity payable on or after the participant's normal retirement age is actuarially equivalent to the balance in the participant’s Cash Balance Account as of the date of distribution. For married participants, the normal form of benefit payment is an actuarially equivalent joint and 50% survivor annuity with a “pop-up” feature providing reduced monthly payments (as compared to the straight life annuity) for the remainder of the participant’s life and, upon the participant’s death, monthly payments to the participant’s surviving spouse for the remainder of the spouse’s life in an amount equal to 50% of the amount being paid to the participant. Under the pop-up feature, if the participant’s spouse predeceases the participant, the participant’s monthly payments increase to the level that would have been provided under the straight life annuity. In addition, the Retirement Plan provides several other annuity payment options and a lump sum payment option that can be elected by participants. All payment options are actuarially equivalent to the straight life annuity. However, in no event will the amount of the lump sum payment be less than the balance in the participant’s Cash Balance Account as of the date of distribution (in some instances the amount of the lump sum distribution may be greater than the balance in the Cash Balance Account due to differences in the mortality table and interest rates used to calculate actuarial equivalency).

If a vested participant dies before his or her Retirement Plan benefit is paid, or commences to be paid, then the participant’s Retirement Plan benefit will be paid to his or her beneficiary(ies). If a participant dies after his or her Retirement Plan benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the participant.

Supplemental Executive Retirement Plan

The SERP provides a benefit to participating Named Executive Officers that supplements the retirement income provided to the executives by the Retirement Plan. All the Named Executive Officers participate in the SERP. A participating Named Executive Officer’s SERP benefit generally vests upon the executive’s completion of five years of participation in the SERP and attainment of age 55 while employed by the Company or any of its affiliates. However, SERP participants as of December 31, 2012, who have not yet attained age 55, including Ms. Harris and Mr. Secrist, have been exempted from the age 55 vesting requirement. All the participating Named Executive Officers ~~except Mr. Doyle,~~ are vested in their SERP benefits. ~~However, Ms. Harris must continue Company service through December 31, 2016 in order to vest additional SERP benefit value after December 31, 2012.~~

~~146~~

The monthly benefit payable under the SERP to a Named Executive Officer (calculated in the form of a straight life annuity payable for the executive’s lifetime commencing at the later of the executive’s date of termination or attainment of age 62) is equal to ~~(1)~~(i) below minus the sum of ~~(2)~~(ii) and ~~(3)~~(iii) below:

~~(1)~~i.One-twelfth (1/12) of the executive’s highest average earnings times the executive’s years of credited service (not in excess of 15) times 3-1/3%. For purposes of the SERP, “highest average earnings” means the average of the executive’s highest three consecutive calendar years of earnings. The three consecutive calendar years must be among the last ten calendar years completed by the executive prior to his or her termination. Prior to December 31, 2012, a participant's highest average earnings was not required to be calculated based on a three consecutive year basis. Executives participating in the SERP as of December 31, 2012 will have their highest average earnings on that date preserved as a minimum value for highest average earnings in the future. “Earnings” for this purpose include base salary and annual bonus, but do not include long-term incentive compensation. An executive will receive one “year of credited service” for each consecutive 12-month period he or she is employed by the Company or its affiliates. If an executive becomes entitled to disability benefits under PSE’s long-term disability plan, then the executive’s highest average earnings will be determined as of the date the executive became disabled, but the executive will continue to accrue years of credited service until he or she begins to receive SERP benefits.

~~(2)~~ii.The monthly amount payable (or that would be payable) under the Retirement Plan to the executive in the form of a straight life annuity commencing as of the first day of the month following the later of the executive’s date of termination or attainment of age 62, including amounts previously paid or segregated pursuant to a qualified domestic relations order.

~~(3)~~iii.The actuarially equivalent monthly amount payable (or that would be payable) to the executive as of the first day of the month following the later of the executive’s date of termination or attainment of age 62 from any pension-type rollover accounts within the Deferred Compensation Plan (including the annual cash balance restoration account). These accounts are described in more detail in the ~~“2015~~“2017 Nonqualified Deferred Compensation” section.

Normal retirement benefits under the SERP generally are paid or commence to be paid within 90 days following the later of the Named Executive Officer’s termination of employment or attainment of age 62. Except as provided below, SERP benefits are normally paid in a lump sum that is equal to the actuarial present value of the monthly straight life annuity benefit. In lieu of the normal form of payment, an executive may elect to receive his or her SERP benefit in the form of monthly installment payments over a period of two to 20 years, in a straight life annuity or in a joint and survivor annuity with a 100%, 75%, 50% or 25% survivor benefit. All payment options are actuarially equivalent to the straight life annuity. An executive may also elect to have his or her SERP benefit transferred to the Deferred Compensation Plan and paid in accordance with his or her elections under that plan.

An executive may elect to have his or her SERP benefit paid, or commence to be paid, upon termination of employment after attaining age 55 but prior to attaining age 62. The SERP benefit of any executive who receives such early retirement benefits will be reduced by 1/3% for each month that the early commencement date precedes the beginning of the month coincident with or next following the date on which the executive attains age 62.

If a participating Named Executive Officer dies while employed by Puget Energy, PSE or any of their affiliates or after becoming vested in his or her SERP benefit, but before his or her SERP benefit has commenced to be paid, then the executive’s surviving spouse will receive a lump sum benefit equal to the actuarial equivalent of the survivor benefit such spouse would have received under the joint and 50% survivor annuity option. This amount will be calculated assuming the executive would have commenced benefit payments in that form on the first day of the month following the later of his or her death or attainment of age 62, with any applicable reductions for early commencement if the executive dies before age 62. If the executive is not married, then no death benefit will be paid. If an executive dies after his or her SERP benefit has commenced to be paid, then any death benefit will be governed by the form of payment elected by the executive.

~~147~~

~~2015~~2017 Nonqualified Deferred Compensation

The following table provides information for each of the Named Executive Officers regarding aggregate executive and Company contributions and aggregate earnings for ~~2015~~2017 and year-end account balances under the Deferred Compensation Plan.


Name	Executive Contributions in 2015 ¹		Registrant Contributions in 2015 ²		Aggregate Earnings in 2015 ³		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 2015 ⁴		Executive Contributions in 2017¹		Registrant Contributions in 2017²		Aggregate Earnings in 2017³		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 2017⁴
Kimberly J. Harris	$	—	$	—	$	11,872	$	—	$	300,074	$	—	$	—	$	12,727	$	—	$	324,915
Daniel A. Doyle	234,993		24,789		2,061		—		483,228		27,866		29,666		84,406		—		940,709
Steve R. Secrist											32,355		21,566		5,222		—		98,893
Marla D. Mellies	8,420		8,993		1,907		—		108,458		10,706		11,131		16,833		—		168,591
Philip K. Bussey	—		—		—		—		—		—		—		—		—		—
Steve R. Secrist	—		—		—		—		—

_______________

The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in ~~2015.~~2017. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, ~~$24,619;~~$27,866; Mr. Secrist, $32,355; Ms. Mellies, ~~$8,420;~~$10,706; and Mr. Bussey, ~~$0; and Mr. Secrist,~~ $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $0; and Mr. Bussey, ~~$0; and Mr. Secrist~~ $0. ~~Mr. Doyle deferred $210,374 of LTIP earnings.~~ The amounts are also included in the applicable column of the Summary Compensation Table for ~~2015.~~2017.


²	The amount reported in this column reflects contributions by PSE consisting of the annual investment plan restoration amount and annual cash balance restoration amount described below. These amounts are also included in the total amounts shown in the All Other Compensation column of the Summary Compensation Table for ~~2015.~~2017.


³	The amount in this column for each executive reflects the change in value of investment tracking funds. Above market earnings on these amounts are included in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column of the Summary Compensation Table for ~~2015.~~2017.


⁴	Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for ~~2015, 2014~~2017, 2016 and ~~2013.~~2015.


Nonqualified Deferred Compensation also Reported
Name	Reported for 2015		Reported for 2014		Reported for 2013		Reported for 2017		Reported for 2016		Reported for 2015
Kimberly J. Harris	$	3,259	$	2,190	$	3,007	$	3,165	$	4,033	$	3,259
Daniel A. Doyle	259,782		132,127		52,664		57,531		273,509		259,782
Steve R. Secrist							53,922		39,223		—
Marla D. Mellies	17,869		16,314		16,740		22,280		15,428		17,869
Philip K. Bussey	—		—		—		—		—		—
Steve R. Secrist	—		—		—

Deferred Compensation Plan

The Named Executive Officers are eligible to participate in the Deferred Compensation Plan and may defer up to 100% of base salary, annual incentive compensation and LTI Plan payments. In addition, each year, executives are eligible to receive Company contributions under the Deferred Compensation Plan to restore benefits not available to them under the Company's tax-qualified plans due to limitations imposed by the Internal Revenue Code. The annual investment plan restoration amount equals the additional matching and any other employer contribution under the 401(k) plan that would have been credited to an electing executive’s 401(k) plan account if the Internal Revenue Code limitations were not in place and if deferrals under the Deferred Compensation Plan were instead made to the 401(k) plan. The annual cash balance restoration amount equals the actuarial equivalent of any reductions in an executive’s accrued benefit under the Retirement Plan due to Internal Revenue Code limitations or as a result of deferrals under the Deferred Compensation Plan. An executive must generally be employed on the last day of the year to receive these Company contributions, unless he or she retires or dies during the year in which case the Company will contribute a prorated amount.

The Named Executive Officers choose how to credit deferred amounts among three investment tracking funds. The tracking funds mirror performance in major asset classes of bonds, stocks, and a money market index. For deferrals prior to 2012, an interest crediting fund was available. The tracking funds differ from the investment funds offered in the 401(k) plan. The ~~2015~~2017 calendar year returns of these tracking funds were:



Vanguard Total Bond Market Index	~~0.41~~	3.57	%
Vanguard 500 Index	~~1.25~~	%21.67
Vanguard Money Market Index	~~0.05~~	%0.81
Interest Crediting Fund (pre-2012 deferrals)	~~4.10~~	%4.14

~~148~~

The Named Executive Officers may change how deferrals are allocated to the tracking funds at any time. Changes generally become effective as of the first trading day of the following calendar quarter.

The Named Executive Officers generally may choose how and when to receive payments under the Deferred Compensation Plan. There are three types of in-service withdrawals. First, an executive may choose an interim payment of deferred amounts by designating a plan year for payment at the time of his or her deferral election. The interim payment is made in a lump sum within 60 days after the last day of the designated plan year, which must be at least two years following the plan year of the deferral. Second, an in-service withdrawal may also be made to an executive upon a qualifying hardship event and demonstrated need. Third, only with respect to amounts deferred and vested prior to 2005, the executive may elect an in-service withdrawal for any reason by paying a 10% penalty. Payments upon termination of employment depend on whether the executive is then eligible for retirement. If the executive's termination occurs prior to his or her retirement date (generally the earlier of attaining age 62 or age 55 with five years of credited service), the executive will receive a lump sum payment of his or her account balance. If the executive’s termination occurs after his or her retirement date, the executive may choose to receive payments in a lump sum or via one of several installment options (fixed amount, specified amount, annual or monthly installments, of up to 20 years).

Potential Payments Upon Termination or Change in Control

The Estimated Potential Incremental Payments Upon Termination or Change in Control table below reflects the estimated amount of incremental compensation payable to each of the Named Executive Officers in the event of (i) ~~an involuntary termination without cause or by the executive for good reason not in connection with~~ a change in control; (ii) ~~a change in control; (iii)~~ an involuntary termination without cause or for good reason in connection with a change in control; ~~(iv)~~(iii) retirement; ~~(v)~~(iv) disability; or ~~(vi)~~(v) death.

Certain Company benefit plans provide incremental benefits or payments in the event of certain terminations of employment. In addition, Ms. Harris and Ms. Mellies are each parties to an Executive Employment Agreement with the Company, dated March 2009. The agreements ~~which~~ provide for benefits or payments upon certain qualifying terminations of employment from the Company following a change in control. The only benefit payable to the Named Executive Officers solely upon a change in control is accelerated vesting of LTI Plan awards, under certain conditions, as described below.

Disability and Life Insurance Plans

If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will receive benefits under the PSE disability plan or life insurance plan available generally to all salaried employees. These disability and life insurance amounts are not reflected in the table below. The Named Executive Officer is also eligible to receive supplemental disability and life insurance. The supplemental monthly disability coverage is 65% of monthly base salary and target annual incentive pay, reduced by (i) amounts receivable under the PSE disability plan generally available to salaried employees and (ii) certain other income benefits. The supplemental life insurance benefit is provided at two times base salary and target annual incentive bonus if the executive dies while employed by PSE with a reduction for amounts payable under the applicable group life insurance policy.

LTI Plan Awards

If a Named Executive Officer’s employment terminates due to disability or death, the executive or his or her estate will be paid a pro-rata portion of LTI Plan awards that were granted in a prior year. In the case of retirement at normal retirement age or approved early retirement, pro-rata LTI Plan awards will be paid in the first quarter following the year of retirement, based on performance through the prior year. In the event of a change in control in which awards are not assumed or substituted, outstanding LTI Plan awards will be paid on a pro-rata basis at the higher of (i) target performance or (ii) actual performance achieved during the performance cycle ending with the fiscal quarter that precedes the change in control.

Employment Agreements with Certain Named Executive Officers

In March 2009, PSE entered into Executive Employment Agreements (Employment Agreements) with each of Ms. Harris and Ms. Mellies (the Covered Executives). The Employment Agreements provide for an employment period of two years following a change in control. In the event of a termination of employment within two years of a change in control (a Covered Termination), a Covered Executive is eligible to receive the payments described below. A change in control generally means a person (or group of persons) (with certain exceptions set forth in the Employment Agreements) acquires (i) beneficial ownership of more than 55% of the total combined voting power of the Company’s securities outstanding immediately after such acquisition (other than through a registered public offering) or (ii) all or substantially all of the Company’s assets.

~~149~~

Payments upon Involuntary Termination without Cause or for Good Reason

If a Covered Executive’s employment is terminated without cause by the Company or is terminated by the Covered Executive for good reason within two years of a change in control, the Covered Executive is eligible to receive the following compensation and benefits:

Lump sum payment of three times the sum of annual base salary and annual incentive bonus for the year in which termination occurs;

Pro-rated annual incentive bonus for the year in which termination occurs (Annual Bonus). Since this amount was earned for ~~2015,~~2017, no amount is shown in the table below;

Supplemental retirement benefit equal to the difference between (x) the actuarial equivalent of the amount the Covered Executive would have received under the Retirement Plan and the SERP had his or her employment continued until the end of two years following the change in control, and (y) the actuarial equivalent of the amount the Covered Executive actually receives or is entitled to receive under the Retirement Plan and SERP; and

Continued group medical, dental, disability and life insurance benefits to the Covered Executive and his or her family for the remainder of the two-year protection period. Benefits will be paid by the Company while the Covered Executive is eligible for COBRA and thereafter by reimbursement of payments made by the Covered Executive for such coverage (including related tax amounts), except that if the Covered Executive becomes re-employed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits under the Employment Agreement will become secondary to those provided by the other employer (the foregoing benefit is referred to as Health and Welfare Benefit Continuation).

Under the Employment Agreements, “cause” and “good reason” have the following meanings:

Cause generally means (i) the willful and continued failure by the Covered Executive to substantially perform the Covered Executive’s duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) for a period of 30 days after written notice of demand for substantial performance has been delivered to the Covered Executive or (ii) the Covered Executive’s willfully engaging in gross misconduct materially and demonstrably injurious to the Company, as determined by the Board after notice to the executive and opportunity for a hearing. No act or failure to act on the Covered Executive’s part is considered “willful” unless the Covered Executive has acted or failed to act with an absence of good faith and without a reasonable belief that the Covered Executive’s action or failure to act was in the best interests of the Company.

Good Reason generally means (i) the assignment of the Covered Executive to a non-officer position with the Company, which the parties agree would constitute a material reduction in the Covered Executive’s authority, duties or responsibilities; (ii) a material diminution in the Covered Executive’s total compensation opportunities under the Employment Agreement; (iii) the Company’s requiring the Covered Executive to be based at any location that represents a material change from the Covered Executive’s location in the Seattle/Bellevue metropolitan area, unless the Covered Executive consents to the relocation; or (iv) a material breach of the Employment Agreement by the Company, provided that, in any of the foregoing, the Company has not remedied the alleged violation(s) within 60 days of notice from the Covered Executive.

Payments upon Retirement, Disability or Death

In the event of a Covered Termination due to voluntary retirement after having attained age 55 with a minimum of five years of service to the Company, a pro-rated Annual Bonus is payable to the Covered Executive. The bonus is payable at the time the Covered Executive otherwise would have received the payment had employment continued, based on the Company’s actual achievement of performance goals.

In the event of a Covered Termination due to disability or death, the Covered Executive is eligible to receive the following compensation and benefits:

•Pro-rated Annual Bonus; and

•Health and Welfare Benefit Continuation.

In addition, upon termination for any of the foregoing reasons, other than by reason of retirement, the Covered Executive is eligible to receive the perquisite of financial planning.

Except as otherwise described above, payments of salary and bonus will be paid after the date of termination, subject to the Covered Executive’s timely execution (and non-revocation) of a general waiver and release of claims.

The Employment Agreements also contain noncompetition and anti-solicitation provisions that restrict the Covered Executive for twelve months after termination from, respectively, engaging in activities related to selling or distributing electric power or natural gas in Washington or soliciting others to leave the Company or causing them to be hired from the Company by another

~~150~~

entity. The Employment Agreements contain a non-disparagement clause and a confidentiality clause pursuant to which the Covered Executives must keep confidential all secret or confidential information, knowledge or data relating to the Company and its affiliates obtained during their employment. The Covered Executives may not disclose any such information, knowledge or data after their respective terminations of employment unless PSE consents in writing or as required by law.

If any payments paid or payable in connection with a change in control while the Company's stock is not traded on an established securities market or otherwise immediately before such change in control, then the Covered Executive will agree to execute a waiver of any “excess parachute payments” (within the meaning of Section 280G of the Internal Revenue Code), provided that the Company agrees to seek, but is not required to obtain, shareholder approval of the amount payable in connection with termination of employment, in which case the waived amounts will be restored to the Covered Executive.

~~151~~

Estimated Potential Incremental Payments Upon Termination or Change in Control

The amounts shown in the table below assume that the termination of employment of a Named Executive Officer or a change in control was effective as of December 31, ~~2015.~~2017. The amounts below are estimates of the incremental amounts that would be paid out to the Named Executive Officer upon a termination of employment or a change in control. Actual amounts payable can only be determined at the time of a termination of employment or a change in control.


	Upon Change in Control		After Change in Control Involuntary Termination w/o Cause or for Good Reason		Retirement		Disability		Death		Upon Change in Control (and awards not assumed or substituted)		After Change in Control Involuntary Termination w/o Cause or for Good Reason		Retirement		Disability		Death
Kimberly J. Harris											$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	$	—	$	5,400,000	$	—	$	—	$	—	—		5,400,000		—		—		—
Long Term Incentive Plan	3,725,369		3,725,369		—		2,968,444		2,968,444		8,846,802		8,846,802		—		8,846,802		8,846,802
SERP (additional years of credited service) ¹	—		—		—		—		—		—		—		—		—		—
Benefits (continuation) ²	—		28,756		—		28,756		28,756		—		29,788		—		29,788		29,788
Supplemental Life Insurance	—		—		—		—		3,000,000		—		—		—		—		3,000,000
Total Estimated Incremental Value	$	3,725,369	$	9,154,125	$	—	$	2,997,200	$	5,997,200	$	8,846,802	$	14,276,590	$	—	$	8,876,590	$	11,876,590
Daniel A. Doyle											$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan											2,175,280		2,175,280		—		2,175,280		2,175,280
SERP (additional years of credited service)¹											—		—		—		—		—
Benefits (continuation)²											—		—		—		—		—
Supplemental Life Insurance											—		—		—		—		1,073,932
Total Estimated Incremental Value											$	2,175,280	$	2,175,280	$	—	$	2,175,280	$	3,249,212
Steve R. Secrist											$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	$	1,090,361	$	1,090,361	$	—	$	871,003	$	871,003	1,629,983		1,629,983		—		1,629,983		1,629,983
SERP (additional years of credited service) ¹	—		—		—		—		—		—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—		—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		943,352		—		—		—		—		767,336
Total Estimated Incremental Value	$	1,090,361	$	1,090,361	$	—	$	871,003	$	1,814,355	$	1,629,983	$	1,629,983	$	—	$	1,629,983	$	2,397,319
Marla D. Mellies											$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	$	—	$	1,303,969	$	—	$	—	$	—	—		1,383,383		—		—		—
Long Term Incentive Plan	655,607		655,607		523,666		523,666		523,666		1,319,202		1,319,202		—		1,319,202		1,319,202
SERP (additional years of credited service)¹	—		409,418		—		—		—		—		447,342		—		—		—
Benefits (continuation) ²	—		40,549		—		40,549		40,549		—		42,756		—		42,756		42,756
Supplemental Life Insurance	—		—		—		—		569,550		—		—		—		—		604,236
Total Estimated Incremental Value	$	655,607	$	2,409,543	$	523,666	$	564,215	$	1,133,765	$	1,319,202	$	3,192,683	$	—	$	1,361,958	$	1,966,194
Philip K. Bussey											$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	658,953		658,953		526,477		526,477		526,477		1,307,720		1,307,720		—		1,307,720		1,307,720
SERP (additional years of credited service) ¹	—		—		—		—		—		—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—		—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		565,408		—		—		—		—		594,016
Total Estimated Incremental Value	$	658,953	$	658,953	$	526,477	$	526,477	$	1,091,885	$	1,307,720	$	1,307,720	$	—	$	1,307,720	$	1,901,736
Steve R. Secrist
Long Term Incentive Plan	$	599,301	$	599,301	$	—	$	476,493	$	476,493
SERP (additional years of credited service) ¹	—		—		—		—		—
Benefits (continuation) ²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		689,554
Total Estimated Incremental Value	$	599,301	$	599,301	$	—	$	476,493	$	1,166,047

_______________


¹	SERP values are shown as the estimated incremental value that the Named Executive Officer would receive at age 62 as a result of the termination event shown in the column, relative to the vested benefit as of December 31, ~~2015.~~2017. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.


²	Benefits (continuation) reflects the value of continued medical, dental, disability and life insurance benefits as well as financial planning benefit in the amount of $5,000 for Ms. Harris and $2,500 for all the other Named Executive Officers eligible for benefits continuation.

~~152~~

Chief Executive Officer Pay Ratio

We are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation for our Chief Executive Officer in accordance with SEC Item 402(u) of Regulation S-K.

For 2017, our last completed fiscal year:

The annual total compensation of our CEO, as reported in the 2017 Summary Compensation Table, was $7,788,167.

The median of the annual total compensation of all our employees (excluding our CEO) was $117,999

As a result, for 2017 the ratio of annual total compensation of our Chief Executive Officer and President, to the median of our annual total compensation of all employees was 66:1.

We identified our median employee by examining the total cash compensation we paid during 2017 to all individuals, excluding our CEO, who were employed by us on December 31, 2017, which totaled approximately 3,160 individuals, all located in the United States (as reported in Item 1. Business), including employees, whether employed on a full-time, part-time or seasonal basis. Total cash compensation consisted of base salary, overtime, paid time off and annual incentives as reflected in our payroll records. We consistently applied this compensation measure and did not make any assumptions, adjustments, or estimates with respect to total cash compensation. We believe that the use of total cash compensation for all employees is a consistently applied compensation measure because it includes all major compensation elements available to employees. Pay for all non-represented employees in the organization is benchmarked periodically to ensure alignment with our compensation philosophy of paying at the market median.

After identifying the median employee based on total cash compensation for 2017, we calculated annual total compensation for such employee for 2017 using the same methodology we use for our named executive officers as set forth in the 2017 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2017 for our median employee included annual salary, annual incentives, company contributions towards benefits including retirement. Annual total compensation for 2017 for our CEO consists of the amount reported in the "Total" column of our 2017 Summary Compensation Table.

Director Compensation for Fiscal Year ~~2015~~2017

The following table sets forth information regarding compensation paid by the Company to the directors named in the table who received compensation from the Company in ~~2015~~2017 for service as directors. We refer to these directors as nonemployee directors. Directors who are employed by the Company or by the Company’s investor-owners are not paid separately for their service and thus are not named in the table below. The directors who are employed by the Company’s investor-owners are: Andrew Chapman, ~~Daniel Fetter, Alan James~~Karl Kuchel, Christopher Leslie, and ~~Christopher Leslie.~~Etienne Middleton. Kimberly Harris is employed by the Company and also serves as a director.

As described in further detail below, the Company’s nonemployee director compensation program in ~~2015~~2017 consisted of quarterly retainer cash fees of $27,500. Additional quarterly retainer amounts associated with serving as Chair of the Board, chairing Board committees, serving on the Audit Committee and meeting fees were also paid in cash.


Name	Fees Earned		Nonqualified Deferred Compensation Earnings ¹		Total		Fees Earned		Nonqualified Deferred Compensation Earnings¹		Total
Scott Armstrong	$	—	$	60,600	$	60,600	$	—	$	146,400	$	146,400
Melanie Dressel	186,817		—		186,817
Melanie Dressel²							30,700		—		30,700
Barbara Gordon							18,333				18,333
Steve Hooper	—		128,033		128,033		—		187,033		187,033
David MacMillan	160,800		—		160,800
David MacMillan³							155,200		—		155,200
Paul McMillan	101,500		—		101,500		139,600		—		139,600
Herbert Simon ²	144,000		3,953		147,953
Mary O. McWilliams							134,800		—		134,800
Christopher Trumpy	151,600		—		151,600		144,400		—		144,400
Mary O. McWilliams	132,400		—		132,400

_______________


¹	Represents earnings accrued on deferred compensation considered to be above market.


²	~~Herbert Simon~~Melanie Dressel’s service as a member of the Board of Directors ended upon her death as of February 19, 2017.


³	David MacMillan resigned from his position as a member of the Board of Directors, ~~of PSE,~~ effective as of January ~~21, 2016.~~18, 2018.

Nonemployee Director Compensation Program

The ~~2015~~2017 nonemployee director compensation program is based on the principles that the level of nonemployee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.

The ~~2015~~2017 compensation program for nonemployee directors was as follows:

A base cash quarterly retainer fee of $27,500;

$1,600 for attendance at each in-person Board and committee meeting; and

$800 for each telephonic meeting lasting 60 minutes or less, and $1,600 for each telephonic meeting lasting more than 60 minutes.

In ~~2015,~~2017, nonemployee directors were paid the following additional cash quarterly retainer fees:

Independent Board Chairman, $13,750;

Chair of the Compensation and Leadership Development Committee, $2,000;

Chair of the Governance and Public Affairs Committees, $1,500;

Chair of the Audit Committee, $2,500; and

Each member of the Audit Committee other than the chair, $1,000.

Nonemployee directors were reimbursed for actual travel and out-of-pocket expenses incurred in connection with their services.

Nonemployee directors are eligible to participate in the Company’s matching gift program on the same terms as all Puget Energy employees. Under this program, the Company matches up to a total of $500 a year in contributions by a director to non-profit organizations that have Internal Revenue Service (IRS) 501(c)(3) tax exempt status and are located in and served the people of PSE’s service territory in Washington State.

~~153~~

Deferral of Compensation

Nonemployee directors may choose to elect to defer all or a part of their cash fees under the Company’s Deferred Compensation Plan for Nonemployee Directors. Nonemployee directors may allocate these deferrals into one or more “measurement funds,” which include an interest crediting fund, an equity index fund and a bond index fund. Nonemployee directors are permitted to make changes in measurement fund allocations quarterly. Steve Hooper and Scott Armstrong ~~and Steve Hooper~~ are the only independent board members to defer any director fees during ~~2015.~~2017.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

Security Ownership of Directors, Executive Officers and Certain Beneficial Owners

The following tables show the number of shares of common stock beneficially owned as of December 31, ~~2015~~2017 by each person or group that we know owns more than 5.0% of Puget Energy’s and PSE’s common stock. No director, executive officer or executive officer named in the Summary Compensation Table in Item 11 of Part III of this report owns any of the outstanding shares of common stock of Puget Energy or PSE. Puget Equico ~~LLC(Puget~~LLC (Puget Equico) and its affiliates beneficially own 100.0% of the outstanding common stock of Puget Energy. Puget Energy holds 100.0% of the outstanding common stock of PSE. Percentage of beneficial ownership is based on 200 shares of Puget Energy common stock and 85,903,791 shares of PSE common stock outstanding as of December 31, ~~2015.~~2017.

Beneficial Ownership Table of Puget Energy and PSE



	Number of Beneficially Owned Shares
Name	Puget Energy	PSE
Puget Equico LLC and affiliates	200^{1, 2}	—
Puget Energy	—	85,903,791³

_______________

^1.1

Information presented above and in this footnote is based on Amendment No. 2 to Schedule 13D/A filed on February 13, 2009 (the Schedule 13D) by, among others, Puget Equico, Puget Intermediate Holdings Inc. (Puget Intermediate), Puget Holdings (Puget Holdings and together with Puget Intermediate, the Parent Entities), Macquarie Infrastructure Partners I (formerly MIP Padua Holdings GP) (MIP)~~, Macquarie Infrastructure Partners II (formerly MIP Washington Holdings, L.P.) (MIP II), FSS Infrastructure Trust (formerly Macquarie-FSS Infrastructure Trust) (FIT)~~, Padua MG Holdings LLC (PMGH) Canada Pension Plan Investment Board (USRE II) Inc. (CPPIB), 6860141 Canada Inc. as trustee for British Columbia Investment Management Corporation (bcIMC), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, ~~MIP II, FIT,~~ PMGH, CPPIB, bcIMC and PIP2PX, the Investors). Puget Equico is a wholly-owned subsidiary of Puget Intermediate, Puget Intermediate is a wholly-owned subsidiary of Puget Holdings and the Investors are the direct or indirect owners of Puget Holdings. The Parent Entities and the Investors are the direct or indirect owners of Puget Equico. Although the Parent Entities and the Investors do not own any shares of Puget Energy directly, Puget Equico, the Parent Entities and the Investors may be deemed to be members of a “group,” within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934, as amended. Accordingly, each such entity may be deemed to beneficially own the 200 shares of Puget Energy common stock owned by Puget Equico. Such shares of common stock constitute 100.0% of the issued and outstanding shares of common stock of Puget Energy. Under Section 13(d)(3) of the Exchange Act and based on the number of shares outstanding, Puget Equico, the Parent Entities and the Investors may be deemed to have shared power to vote and shared power to dispose of such shares of Puget Energy common stock that may be beneficially owned by Puget Equico. However, each of Puget Equico, the Parent Entities and the Investors expressly disclaims beneficial ownership of such shares of common stock other than those shares held directly by such entity. According to the Schedule 13D, as of February 13, 2009:

The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, 10885 NE 4th Street, Bellevue, WA 98004.

The address of the principal office of MIP ~~and MIP II~~ is 125 West 55th Street, Level 22, New York, NY 10019.

~~The address of the principal office of FIT is Level 21, 83 Clarence Street, Sydney, Australia NSW 2000.~~

The address of the principal office of PMGH is 125 West 55th Street, Level 22, New York, NY 10019.

The address of the principal office of CPPIB is One Queen Street East, Suite 2500, P.O. Box 101, Toronto, Ontario, Canada M5C 2W5.

The address of the principal office of bcIMC is Suite 300-2950 Jutland Road, Victoria, British Columbia, Canada V8T 5K2.

The address of the principal office of PIP2PX and PIP2GV is 1100, 10830 Jasper Avenue, Edmonton, Alberta, Canada T5J 2B3.

^2.2

Pursuant to that certain Pledge Agreement dated as of May 10, 2010, as amended on February 10, 2012, made by Puget Equico to JPMorgan Chase Bank, N.A., as administrative agent, the outstanding stock of Puget Energy held by Puget Equico was pledged by Puget Equico to secure the obligations of Puget Energy under (a) the Credit Agreement dated as of February 10, 2012, as amended and extended April 15, 2014, among Puget Energy, JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto, and (b) the senior secured notes issued on December 6, 2010, June 3, 2011, June 15, 2012 and May 12, 2015.

^3.3

Pursuant to that certain Borrower's Security Agreement dated as of May 10, 2010, as amended on February 10, 2012, the outstanding stock of PSE held by Puget Energy was pledged by Puget Energy to secure its obligations under (a) the Credit Agreement dated as of February 10, 2012, as amended and extended April 15, 2014, among Puget Energy as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the other agents party thereto, and the lenders party thereto, and (b) the senior secured notes issued on December 6, 2010, June 3, 2011, June 15, 2012 and May 12, 2015.

~~154~~

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Our Boards of Directors have adopted a written policy for the review and approval or ratification of related person transactions. Under the policy, our directors and executive officers are expected to disclose to our Chief Compliance Officer the material facts of any transaction that could be considered a related person transaction promptly upon gaining knowledge of the transaction. A related person transaction is generally defined as any transaction required to be disclosed under Item 404(a) of Regulation S-K, the SEC’s related person transaction disclosure rule.

Any transaction reported to the Chief Compliance Officer will be reviewed according to the following procedures:

If the Chief Compliance Officer determines that disclosure of the transaction is not required under the SEC’s related person transaction disclosure rule, the transaction will be deemed approved and will be reported to the Audit Committee.

If disclosure is required, the Chief Compliance Officer will submit the transaction to the Chair of the Audit Committee who will review and, if authorized, will determine whether to approve or ratify the transaction. The Chair is authorized to approve or ratify any related person transaction involving an aggregate amount of less than $1.0 million or when it would be impracticable to wait for the next Audit Committee meeting to review the transaction.

If the transaction is outside the Chair’s authority, the Chair will submit the transaction to the Audit Committee for review and approval or ratification.

When determining whether to approve or ratify a related person transaction, the Chair of the Audit Committee or the Audit Committee, as applicable, will review relevant facts regarding the related person transaction, including:

The extent of the related person’s interest in the transaction;

Whether the terms are comparable to those generally available in ~~arms’~~arm's length transactions; and

Whether the related person transaction is consistent with the best interests of the Company.

If any related person transaction is not approved or ratified, the Committee may take such action as it may deem necessary or desirable in the best interests of the Company and its shareholders.

Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017, was the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elected Group Health as their medical provider prior to its acquisition by Kaiser Permanente. PSE made no payments to Group Health, as all payments were made after its acquisition by Kaiser Permanente for medical coverage for the year ended December 31, 2017.

Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who is a ~~principal~~partner at ~~the law firm Riddell Williams P.S., one of PSE’s primary law firms for nearly 50 years.~~Summit Law Group, which provides legal services to PSE. In ~~2015 and 2014, Riddell Williams~~2017, Summit Law Group was paid ~~$1.81~~$0.8 million ~~and $1.98 million, respectively,~~ for legal services provided to PSE and Mr. Branum iswas among the lawyers at ~~Riddell Williams~~Summit Law Group who provided such legal services. This work was performed under the supervision of PSE's General ~~Counsel and the compensation arrangements were comparable to other regional law firms providing legal services to PSE.~~

On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the president and chief executive officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2015 and 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest each year to U.S. Bank N.A. and its subsidiaries or affiliates.

Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $20.3 million and $17.7 million for medical coverage for the year ended December 31, 2015 and 2014, respectively.Counsel.

Board of Directors and Corporate Governance

Independence of the Board

The Boards of Puget Energy and PSE have reviewed the relationships between Puget Energy and PSE (and their respective subsidiaries) and each of their respective directors. Based on this review, the Boards have determined that of the members constituting the Boards, Steven Hooper (member of the Boards of both Puget Energy and PSE), ~~Melanie Dressel~~Scott Armstrong (member of the ~~Boards~~Board of ~~both~~PSE and added to the Board of Puget Energy ~~and PSE)~~at the November, 2017 Board Meeting), and ~~Scott Armstrong~~Barbara Gordon (member of the Board of PSE) are independent under the NYSE corporate governance listing standards and also meet the definition of an “Independent Director” under the Company’s Amended and Restated Bylaws. Under the Amended and Restated Bylaws of Puget Energy and PSE, an Independent Director is a director

~~155~~

who: ~~(a)~~(i) shall not be a member of Puget Holdings (referred to as a Holdings Member) or an affiliate of any Holdings Member (including by way of being a member, stockholder, director, manager, partner, officer or employee of any such member), ~~(b)~~(ii) shall not be an officer or employee of PSE, ~~(c)~~(iii) shall be a resident of the state of Washington, and ~~(d)~~(iv) if and to the extent required with respect to any specific director, shall meet such other qualifications as may be required by any applicable regulatory authority for an independent director or manager. The Company’s definition of "Independent Director" is available in the Corporate Governance Guidelines at www.pugetenergy.com.

In making these independence determinations, the Boards have established a categorical standard that a director’s independence is not impaired solely as a result of the director, or a company for which the director or an immediate family member of the director serves as an executive officer, making payments to PSE for power or natural gas provided by PSE at rates fixed in conformity with law or governmental authority, unless such payments would automatically disqualify the director under the NYSE’s corporate governance listing standards. The Boards have also established a categorical standard that a director’s independence is not impaired if a director is a director, employee or executive officer of another company that makes payments to or receives payments from Puget Energy, PSE or any of their affiliates, for property or services in an amount which is less than the greater of $1.0 million or one percent of such other company’s consolidated gross revenue, determined for the most recent fiscal year. These categorical standards will not apply, however, to the extent that Puget Energy or PSE would be required to disclose an arrangement as a related person transaction pursuant to Item 404 of Regulation S-K.

The Boards considered all relationships between its directors and Puget Energy and PSE (and their respective subsidiaries), including some that are not required to be disclosed in this report as related-person transactions. ~~Messrs~~Mr. Hooper and Mr. Armstrong, Ms. McWilliams and ~~Ms.~~former Board member Melanie Dressel serve (or served) as directors or officers of, or otherwise ~~have~~have/had a financial interest in, entities that make payments to PSE for energy services provided to those entities at tariff rates established by the Washington Commission. These transactions fall within the first categorical independence standard described above. Because these relationships either fall within the Boards' categorical independence standards or involve an amount that is not material to the Company or the other entity, the Boards have concluded that none of these relationships impair the independence of the applicable directors.

Executive Sessions

Non-management directors meet in executive session on a regular basis, generally on the same date as each scheduled Board meeting. ~~Ms. Dressel,~~Mr. Hooper, who is not a member of management, presides over the executive sessions. Interested parties may communicate with the non-management directors of the Board through the procedures described in Item 10, "Directors, Executives Officers and Corporate Governance" of Part III of this ~~annual report~~Form 10-K under the section “Communications with the Board.”

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, for the years ended December 31, 2017 and 2016 were as follows:


	2015				2014				2017				2016
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE		Puget Energy		PSE		Puget Energy		PSE
Audit fees ¹	$	2,413	$	2,128	$	2,041	$	1,878	$	2,777	$	2,546	$	2,597	$	2,397
Audit related fees ²	45		45		111		111		22		22		47		47
Tax fees ³	—		—		31		31		—		—		—		—
Other fees⁴	52		52		52		52		337		337		383		383
Total	$	2,510	$	2,225	$	2,235	$	2,072	$	3,136	$	2,905	$	3,027	$	2,827



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	/ /



	Page
Definitions	4
Forward-Looking Statements	5
Part I
1. Business	7
General	7
Regulation and Rates	89
Electric Utility Operating Statistics	1412
Electric Supply	1614
Natural Gas Utility Operating Statistics	1918
Natural Gas Supply for Natural Gas Customers	2120
Energy Efficiency	2322
Environment	2322
Recent and Future Environmental Law and Regulation	2423
Executive Officers of the Registrants	2725
1A. Risk Factors	2725
1B. Unresolved Staff Comments	3330
2. Properties	3330
3. Legal Proceedings	3330
4. Mine Safety Disclosures	3430

Part II
5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	3431
6. Selected Financial Data	3532
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	3633
7A. Quantitative and Qualitative Disclosures about Market Risk	5763
8. Financial Statements and Supplementary Data	6166
Report of Management and Statement of Responsibility	6267
Report of Independent Registered Public Accounting Firm – Puget Energy	6368
Report of Independent Registered Public Accounting Firm – Puget Sound Energy	6470
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~129~~132
9A. Controls and Procedures	~~129~~132
9B. Other Information	~~130~~133

Part III
10. Directors, Executive Officers and Corporate Governance	~~130~~134
11. Executive Compensation	~~133~~136
12. Security Ownership of Certain Beneficial Owners and Management and Related	~~154~~160
Shareholder Matters
13. Certain Relationships and Related Transactions, and Director Independence	~~155~~161
14. Principal Accountant Fees and Services	~~156~~162

Part IV
15. Exhibits and Financial Statement Schedules	~~157~~163
16. ~~Signatures~~Form 10-K Summary	~~158~~163
Exhibit Index	~~160~~164
Signatures	170



Utility Plant Additions/Retirements 5-Year Total	2013-2017
(Dollars in Thousands)	Electric			Natural Gas			Common
Additions	$	2,148,599		$	868,919		$	499,934
Retirements	(537,049		)	(125,042		)	(257,473		)
Net Utility Plant	$	1,611,550		$	743,877		$	242,461


	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2017			2016			2015
Average kWh used per customer:
Residential	10,470			10,773			11,256			10,953			10,404			10,470
Commercial	73,120			73,360			76,095			71,670			71,129			73,120
Industrial	366,324			356,877			353,931			357,404			357,143			366,324
Other	15,096			16,354			18,691			12,977			14,022			15,096
Average revenue per customer:
Residential	$	1,093		$	1,044		$	1,166		$	1,234		$	1,157		$	1,093
Commercial	7,051			6,798			7,074			7,036			6,973			7,051
Industrial	33,262			31,350			31,213			33,191			33,130			33,262
Other	3,218			3,272			3,639			2,935			3,097			3,218
Average retail revenue per kWh sold:
Residential	$	0.1044		$	0.0969		$	0.1036		$	0.1127		$	0.1112		$	0.1044
Commercial	0.0964			0.0927			0.0930			0.0982			0.0980			0.0964
Industrial	0.0908			0.0878			0.0882			0.0929			0.0928			0.0908
Other	0.2131			0.2001			0.1947			0.2262			0.2209			0.2131
Average retail revenue per kWh sold	$	0.1006		$	0.0950		$	0.0986		$	0.1058		$	0.1048		$	0.1006
Heating degree days	3,800			3,829			4,734			4,584			3,823			3,800
Percent of normal - NOAA¹30-year average	80.5		%	81.2		%	100.3		%
Load factor ²	56.2		%	52.3		%	51.2		%
Percent of normal - NOAA²30-year average										97.2		%	81.0		%	80.5		%
Load factor³										51.6		%	56.2		%	56.2		%


	Peak Power Resources At December 31,						Energy Production At December 31,						Peak Power Resources At December 31,						Energy Production At December 31,
	2015			2014			2015			2014			2017			2016			2017			2016
	MW	%		MW	%		MWh	%		MWh	%		MW	%		MW	%		MWh	%		MWh	%
Purchased resources:
Columbia River PUD contracts	708	14.5	%	709	14.5	%	3,325,450	13.9	%	3,318,746	14.0	%	711	15.0	%	708	14.6	%	3,355,134	13.3	%	3,371,827	13.7	%
Other hydroelectric	85	1.7		85	1.7		179,057	0.7		185,943	0.8		72	1.5		79	1.6		281,619	1.1		365,670	1.5
Other producers	463	9.5		464	9.5		2,200,098	9.2		815,640	3.4		284	6.0		387	8.0		3,679,623	14.6		2,999,171	12.1
Wind	56	1.1		56	1.2		130,777	0.5		140,716	0.6		56	1.2		56	1.2		119,690	0.5		138,148	0.6
Short-term wholesale energy purchases	N/A	—		N/A	—		5,390,896	22.5		7,590,442	32.1		N/A	—		N/A	—		7,049,060	27.8		6,154,767	25.0
Total purchased	1,312	26.8	%	1,314	26.9	%	11,226,278	46.8	%	12,051,487	50.9	%	1,123	23.7	%	1,230	25.4	%	14,485,126	57.3	%	13,029,583	52.9	%
Company-controlled resources:
Hydroelectric	254	5.2	%	254	5.2	%	706,231	2.9	%	1,000,201	4.2	%	254	5.4	%	254	5.2	%	864,821	3.4	%	933,522	3.8	%
Coal	677	13.9		677	13.8		4,495,032	18.8		4,509,567	19.0		677	14.3		677	14.0		4,463,705	17.6		4,529,179	18.4
Natural gas/oil	1,871	38.3		1,871	38.3		5,830,318	24.3		4,154,983	17.5		1,908	40.3		1,908	39.4		3,822,462	15.1		4,152,205	16.9
Wind	773	15.8		773	15.8		1,715,433	7.2		1,975,753	8.3		773	16.3		773	16.0		1,674,790	6.6		1,962,702	8.0
Other¹													2	—		2	—		—	—		—	—
Total company-controlled	3,575	73.2	%	3,575	73.1	%	12,747,014	53.2	%	11,640,504	49.1	%	3,614	76.3	%	3,614	74.6	%	10,825,778	42.7	%	11,577,608	47.1	%
Total resources	4,887	100.0	%	4,889	100.0	%	23,973,292	100.0	%	23,691,991	100.0	%	4,737	100.0	%	4,844	100.0	%	25,310,904	100.0	%	24,607,191	100.0	%



/X/	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



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



Commission File Number	Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, zip code 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



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement and Environmental Obligations
aMW	Average Megawatt
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BPA	Bonneville Power Administration
Colstrip	Colstrip, Montana coal-fired steam electric generation facility
Dth	Dekatherm (one Dth is equal to one MMBtu)
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EPA	Environmental Protection Agency
ERF	Expedited Rate Filing
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse Gases
GRC	General Rate Case
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association
JPUD	Jefferson County Public Utility District
kW	Kilowatt (one kW equals one thousand watts)
kWh	Kilowatt Hour (one kWh equals one thousand watt hours)
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
LTI Plan	Long-Term Incentive Plan
MMBtus	One Million British Thermal Units
MW	Megawatt (one MW equals one thousand kW)
MWh	Megawatt Hour (one MWh equals one thousand kWh)
NAESB	North American Energy Standards Board
NOAA	National Oceanic and Atmospheric Administration
NPNS	Normal Purchase Normal Sale
NWP	Northwest Pipeline, GPLLC
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment
PCORC	Power Cost Only Rate Case
PGA	Purchased Gas Adjustment
PSE	Puget Sound Energy, Inc.
PTC	Production Tax Credit
PUDs	Washington Public Utility Districts
Puget Energy	Puget Energy, Inc.
Puget Equico	Puget Equico, LLC
Puget Holdings	Puget Holdings, LLC
REC	Renewable Energy Credit
REP	Residential Exchange Program
SEC	United States Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
TCJA	Tax Cuts and Jobs Act
Washington Commission	Washington Utilities and Transportation Commission
WSPP	WSPP, Inc.



•	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;
•	Changes in tax law as a result of the Tax Cuts and Jobs Act legislation and uncertain interpretations related thereto;
•	Inability to realize deferred tax assets and use Production Tax Credits (PTCs) due to insufficient future taxable income;
•	~~Inability to manage costs during the rate stay out period through March 31, 2016, which would cause increases in costs of operations;~~
•	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, flu pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
•	Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
•	Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
•	Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
•	The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
•	PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
•	Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
•	The ability to restart generation following a regional transmission disruption;
•	The ability of a natural gas or electric plant to operate as intended;



•	Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;



•	Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
•	Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
•	The ability to renew contracts for electric and natural gas supply and the price of renewal;
•	Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
•	General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
•	The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
•	The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
•	Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
•	Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
•	Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
•	The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;
•	The ability to maintain effective internal controls over financial reporting and operational processes;
•	Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally; and
•	Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.


¹	At December 31, ~~2015,~~2017 and 2016, approximately ~~386,100~~398,518 and 392,806 customers purchased both electricity and natural gas from PSE, ~~as compared to 381,500 at December 31, 2014.~~respectively.



	December 31,					December 31,
Retail Revenue by Class	2017		2016		Percent	2017		2016		Percent
(Dollars in Thousands)	Electric				Change	Natural Gas				Change
Residential	$	1,232,075	$	1,138,871	8.2%	$	686,438	$	578,955	18.6%
Commercial	892,360		872,057		2.3	274,907		235,695		16.6
Industrial	112,817		113,469		(0.6)	21,071		19,643		7.3
Other	32,313		30,982		4.3	21,718		20,322		6.9
Total	$	2,269,565	$	2,155,379	5.3%	$	1,004,134	$	854,615	17.5%



Utility Plant Balance	December 31, 2017
(Dollars in Thousands)	Electric				Natural Gas				Common
Distribution	$	3,757,600	36.7	%	$	3,532,397	91.0	%	$	—	—	%
Generation	3,948,102		38.6		5,956		0.2		—		—
Transmission	1,471,337		14.4		—		—		—		—
General Plant & Other	1,055,732		10.3		344,380		8.8		843,145		100.0
Total	$	10,232,771	100.0	%	$	3,882,733	100.0	%	$	843,145	100.0	%



Rate Filings	Electric	Natural Gas
Baseline rates	Yes	Yes
Annual rate plan increase	Yes	Yes
Expedited rate filing rider	Yes	Yes
Merger credit	No	No
Power cost only rates mechanism	No	N/A
Federal incentive tracker	No	N/A
Low income rates tracker	No	No
Pipeline cost recovery mechanism tracker	N/A	No
Prior year decoupling deferral tracker	No	No
Property tax tracker	No	No
Renewable energy credit tracker	No	N/A
Residential exchange credits tracker	No	N/A
Conservation costs rider	No	No
PGA rider	N/A	No



Effective Date	Average Percentage Increase (Decrease) in Rates		Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2016	(0.2	)%	$	(57.3	)
January 1, 2015	(0.2	)	(55.2		)
January 1, 2014	(0.3	)	(58.5		)
February 1, 2013	(2.8	)	(58.4		)



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



Effective Date	Average Percentage Increase (Decrease) in Rates		Increase (Decrease) in Revenue (Dollars in Millions)
December 1, 2014	(0.9	)%	$	(19.4	)
November 1, 2013	(0.5	)	(10.5		)


¹	Includes ~~amortization of prior year collection/refund, reduction related to excess~~decoupling cash collections, rate of return excess earnings, and ~~a reduction related to amounts that will not be collected within 24 months.~~decoupling 24-month revenue reserve.


²³	Average ~~Megawatt~~megawatt (aMW) usage by customers divided by their maximum usage.


¹	It is estimated that the Glacier Battery Storage has delivered approximately 746.5 and 250.0 MWh as of December 31, 2017 and 2016, respectively.


¹	Net Maximum Capacity is the capacity a unit can sustain over a specified period of time when not restricted by ambient conditions or deratings, less the losses associated with auxiliary loads.


2	In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022.


3	The FERC license authorizes the full 54.4 MW; however, the project's water right issued by the State Department of Ecology limits flow to 2,500 cubic feet and therefore output to 47.7MW.


			Company’s Annual Purchasable Amount (Approximate)					Company’s Annual Share (Approximate)
Project	Contract Expiration Year	License Expiration Year	Percent of Output		MW Capacity	Contract Expiration Year	License Expiration Year	Percent of Output		MW Capacity
Chelan County PUD:
Rock Island Project	2031	2029	25.0	%	156	2031	2029	25.0	%	156
Rocky Reach Project	2031	2052	25.0	%	325	2031	2052	25.0	%	325
Douglas County PUD:
Wells Project	2018	2052	29.9	%	251
Wells Project¹						2028	2052	29.9	%	251
Grant County PUD:
Priest Rapids Development	2052		0.6	%	8	2052	2052	0.6	%	6
Wanapum Development	2052		0.6	%	9	2052	2052	0.6	%	7
Total					749					745


¹	In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028.



Peak Firm Natural Gas Supply ¹	At December 31,
	2015				2014
	Dth per Day		%		Dth per Day		%
Purchased gas supply:
British Columbia	210,000		23.4	%	243,000		26.4	%
Alberta	110,000		12.2	%	99,000		10.7	%
United States	118,100		13.1	%	127,000		13.8	%
Total purchased natural gas supply	438,100		48.7	%	469,000		50.9	%
Purchased storage capacity:
Jackson Prairie	48,400		5.4	%	48,400		5.3	%
Clay Basin	61,600		6.8	%	52,700		5.7	%
Total purchased storage capacity	110,000		12.2	%	101,100		11.0	%
Owned storage capacity:
Jackson Prairie	348,700		38.8	%	348,700		37.8	%
Propane and LNG	2,500		0.3	%	2,500		0.3	%
Total owned storage capacity	351,200		39.1	%	351,200		38.1	%
Total peak firm natural gas supply	899,300		100.0	%	921,300		100.0	%
Other and commitments with third parties	(6,200	)	*		(5,900	)	*
Total net peak firm natural gas supply	893,100		*		915,400		*


¹	~~All peak firm gas supplies and storage are connected to PSE’s market with firm transportation capacity.~~



~~Name~~	~~Age~~	~~Offices~~
~~K. J. Harris~~	51	~~President and Chief Executive Officer since March 2011; President July 2010 – February 2011.~~
~~D. A. Doyle~~	57	~~Senior Vice President and Chief Financial Officer since November 2011. Prior to PSE, he was President of Wisconsin Sports Development Corporation June 2010 – November 2011.~~
~~S. R. Secrist~~	54	~~Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014.~~
~~M. J. Stranik~~	52	~~Controller and Principal Accounting Officer since June 2012; Assistant Controller - Financial Reporting March 2011 – June 2012; Assistant Controller November 2002 – March 2011.~~



Name	Age	Offices
K. J. Harris	53	President and Chief Executive Officer since March 2011
D. A. Doyle	59	Senior Vice President and Chief Financial Officer since November 2011
S. R. Secrist	56	Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014; Vice President, General Counsel and Chief Ethics and Compliance Officer January 2011-January 2014
S. J. King	34	Controller and Principal Accounting Officer since November 2, 2017. Senior Manager (audited utility, technology and telecommunication companies) at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016; Senior Associate at PwC July 2010 - July 2013


Puget Sound Energy Summary of Operations	Year Ended December 31,
Puget Energy
Summary of Operations											Year Ended December 31,
(Dollars in Thousands)	2015		2014		2013		2012		2011		2017		2016		2015		2014		2013
Operating revenue	$	3,093,258	$	3,116,123	$	3,187,335	$	3,216,259	$	3,319,803	$	3,460,276	$	3,164,301	$	3,092,700	$	3,113,171	$	3,187,297
Operating income	656,138		568,693		735,574		692,989		431,043		760,497		785,384		671,925		577,851		755,160
Net income	304,189		236,614		356,129		356,170		204,120		175,194		312,899		241,179		171,835		285,728

Total assets at year end	$	10,829,535	$	10,581,415	$	10,667,830	$	10,559,956	$	9,995,939
Total assets at year-end											$	13,690,789	$	13,266,380	$	12,814,254	$	12,637,946	$	12,781,672
Long-term debt	3,524,384		3,351,259		3,513,258		3,513,258		3,523,845		5,207,929		5,104,073		5,077,518		4,957,951		4,943,577
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000
Capital lease obligations	378		9,473		17,051		24,629		32,207		1,129		645		378		9,473		17,051


Puget Energy Summary of Operations	Year Ended December 31,
Puget Sound Energy
Summary of Operations											Year Ended December 31,
(Dollars in Thousands)	2015		2014		2013		2012		2011		2017		2016		2015		2014		2013
Operating revenue	$	3,092,700	$	3,113,171	$	3,187,297	$	3,215,156	$	3,318,765	$	3,460,276	$	3,164,618	$	3,093,258	$	3,116,123	$	3,187,335
Operating income	671,925		577,851		755,160		715,535		474,940		748,609		774,993		656,138		568,693		735,574
Net income	241,179		171,835		285,728		273,821		123,290		320,054		380,581		304,189		236,614		356,129

Total assets at year end	$	12,852,619	$	12,673,603	$	12,820,571	$	12,781,838	$	12,305,372
Total assets at year-end											$	11,731,706	$	11,297,080	$	10,799,513	$	10,552,727	$	10,636,634
Long-term debt	5,115,883		4,831,608		4,982,476		5,083,200		5,027,367		3,499,911		3,497,298		3,494,362		3,484,571		3,482,062
Junior subordinated notes	250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000		250,000
Capital lease obligations	378		9,473		17,051		24,629		32,207		1,129		645		378		9,473		17,051