UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



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

For the fiscal year ended December 31, ~~2016~~2019



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



			For the transition period from ___________ to ___________



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



1-16305	PUGET ENERGY, INC. A Washington Corporation ~~10885~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-1969407



1-4393	PUGET SOUND ENERGY, INC. A Washington Corporation ~~10885~~355 110th Ave NE 4^th ~~Street, Suite 1200~~ Bellevue, Washington ~~98004-5591~~98004 (425) 454-6363	91-0374630

Securities registered pursuant to Section 12(b) of the Act: None

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

N/A

Securities registered pursuant to Section 12(g) of the Act: None

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

N/A

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

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

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

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

Puget Energy, Inc.

Yes

/X/

/ /

Puget Sound Energy, Inc.

Yes

/X/

/ /

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/

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

Puget Energy, Inc.

Large accelerated filer

/ /

Accelerated filer

/ /

Non-accelerated filer

/X/

Smaller reporting company

/ /

Emerging growth company

/ /

Puget Sound Energy, Inc.

Large accelerated filer

/ /

Accelerated filer

/ /

Non-accelerated filer

/X/

Smaller reporting company

/ /

Emerging growth company

/ /

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

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

Puget Energy, Inc.

Yes

/ /

/X/

Puget Sound Energy, Inc.

Yes

/ /

/X/

As of February 6, 2009, all of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.

All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.

This Report on Form 10-K is a combined report being filed separately by: Puget Energy, Inc. and Puget Sound Energy, Inc. Puget Sound Energy, Inc. makes no representation as to the information contained in this report relating to Puget Energy, Inc. and the subsidiaries of Puget Energy, Inc. other than Puget Sound Energy, Inc. and its subsidiaries.

INDEX



		Page
Definitions		54
Forward-Looking Statements		65
Part I
1. ~~Business~~	8
1. ~~General~~Business		87
General		9
Regulation and Rates		109
Electric Utility Operating Statistics		1413
Electric Supply		1615
Natural Gas Utility Operating Statistics		19
Natural Gas Supply for Natural Gas Customers		212 1
Energy Efficiency		23
Environment		23
Recent and Future Environmental Law and Regulation		24
Executive Officers of the Registrants		27
1A. Risk Factors		27
1B. Unresolved Staff Comments		3334
2. Properties		3334
3. Legal Proceedings		3334
4. Mine Safety Disclosures		34

Part II
5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities		34
6. Selected Financial Data		35
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		363 6
7A. Quantitative and Qualitative Disclosures about Market Risk		5860
8. Financial Statements and Supplementary Data		6263
Report of Management and Statement of Responsibility		6364
Report of Independent Registered Public Accounting Firm – Puget Energy		6465
Report of Independent Registered Public Accounting Firm – Puget Sound Energy		6567
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~128~~134
9A. Controls and Procedures		~~128~~134
9B. Other Information		~~129~~135

Part III
10. Directors, Executive Officers and Corporate Governance		~~129~~136
11. Executive Compensation		~~132~~139
12. Security Ownership of Certain Beneficial Owners and Management and Related		~~155~~160
Shareholder Matters
13. Certain Relationships and Related Transactions, and Director Independence		~~156~~161
14. Principal Accountant Fees and Services		~~157~~162

Part IV
15. Exhibits and Financial Statement Schedules		~~158~~16 3
16. Form 10-K Summary		~~158~~163
~~Signatures~~Exhibit Index		~~159~~164
~~Exhibit Index~~Signatures		~~161~~170

DEFINITIONS



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~~kW		~~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.

FORWARD-LOOKING STATEMENTS

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

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

In addition to other factors and matters discussed elsewhere in this report, ~~including the risks described in Item 1A, "Risk Factors",~~ some important risks that could cause actual results or outcomes for Puget Energy and PSE to differ materially from past results and those discussed in the forward-looking statements include:



•			Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;
•			Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
•			Changes in tax law, related regulations or differing interpretation, including as a result of the Tax Cuts and Jobs Act (TCJA), or enforcement of applicable law by the Internal Revenue ~~Service~~Services (IRS) or other taxing jurisdiction and PSE's ability to recover costs in a timely manner arising from such changes;
•			Inability to realize deferred tax assets and use ~~Production Tax Credits~~production tax credits (PTCs) due to insufficient future taxable income;
•			Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, ~~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;
•			Variable wind conditions, which can impact PSE's ability to generate electricity from the wind facilities;
•			The ability to renew contracts for electric and natural gas supply and the price of renewal;
•			Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
•			General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
•			The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
•			The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
•			Opposition and social activism that may hinder PSE's ability to perform work or construct infrastructure;
•			Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
•			Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
•			The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;
•			The ability to maintain effective internal controls over financial reporting and operational processes;
•			Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally; and
•			Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.

Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. For further information, see the reports on Form 10-Q and current reports on Form 8-K.

PART I

ITEM 1. BUSINESS

General

Puget Energy is an energy services holding company incorporated in the state of Washington in 1999. Substantially, all of its operations are conducted through its regulated subsidiary, ~~PSE,~~Puget Sound Energy, Inc. (PSE), a utility company. Puget Energy also hasa wholly-owned, non-regulated subsidiary, ~~named~~ Puget LNG, LLC (Puget LNG)~~. Puget LNG,~~, which was formed ~~on November 29,~~in 2016 and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington.

Puget Energy is owned through a holding company structure by Puget Holdings, LLC (Puget Holdings). All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including ~~Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust,~~ the Canada Pension Plan Investment Board, ~~(CPPIB),~~ the British Columbia Investment Management Corporation ~~and~~(BCI), the Alberta Investment Management ~~Corporation. All~~Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17th, 2019. Puget ~~Energy’s common stock is indirectly owned by Puget Holdings.~~Energy and PSE are collectively referred to herein as “the Company.”

Corporate Strategy

Puget Energy is the direct parent company of PSE, the oldest and largest electric and natural gas utility headquartered in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy’s business strategy is to generate stable earnings and cash flow by offering reliable electric and natural gas service in a cost-effective manner through PSE.

Customers and Revenue Overview

PSE is a public utility incorporated in the state of Washington in 1960. PSE furnishes electric and natural gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region.

The following tables present the number of PSE customers and revenue by customer class for electric and natural gas as of December 31, ~~2016~~2019, and ~~2015:~~2018:


	2016	2015		2016	2015
	December 31,		Percent	December 31,		Percent		December 31,				December 31,
Customer Count by Class	Electric		Change	Natural Gas		Change	Customer Count by Class	2019	2018	Percent	2019	2018	Percent
(in thousands)							(in thousands)	Electric			Change	Natural Gas		Change
Residential	992,959	976,583	1.7%	756,330	742,494	1.9%	Residential	1,033	1,018	1.5%	788	778	1.2%
Commercial	125,737	123,681	1.7	55,671	55,208	0.8	Commercial	130	129	1.0%	57	56	0.5%
Industrial	3,417	3,423	(0.2)	2,365	2,397	(1.3)	Industrial	3	3	(0.7)%	2	2	(0.2)%
Other	6,591	6,354	3.7	227	227	—	Other	8	7	6.6%	—	—	(3.4)%
Total¹	1,128,704	1,110,041	1.7%	814,593	800,326	1.8%	Total¹	1,174	1,157	1.5%	847	836	1.3%

_______________


¹	~~At December 31, 2016, approximately 392,806 customers purchased both electricity and natural gas from PSE as compared to 386,100 at December 31, 2015.~~

¹At December 31, 2019, and 2018, approximately 409,820 and 404,540 customers purchased both electricity and natural gas from PSE, respectively.


								December 31,							December 31,
	2016	2015		2016	2015
Revenue by Class	December 31,		Percent	December 31,		Percent
Retail Revenue by Class							Retail Revenue by Class	2019		2018		Percent	2019		2018		Percent
(Dollars in Thousands)	Electric		Change	Natural Gas		Change	(Dollars in Thousands)	Electric					Change		Natural Gas			Change
Residential	$1,138,871	$1,061,117	7.3%	$578,955	$597,572	(3.1)%	Residential	$	1,139,356	$	1,147,260	(0.7)%	$	613,617	$	598,923	2.5%
Commercial	872,057	867,786	0.5	235,695	268,044	(12.1)	Commercial	854,910		885,457		(3.4)%	236,059		239,552		(1.5)%
Industrial	113,469	114,223	(0.7)	19,643	22,420	(12.4)	Industrial	105,020		110,607		(5.1)%	16,322		18,198		(10.3)%
Other	30,982	30,359	2.1	20,322	18,666	8.9	Other	37,920		32,596		16.3%	20,283		19,984		1.5%
Total	$2,155,379	$2,073,485	9.2%	$854,615	$906,702	(18.7)%	Total	$	2,137,206	$	2,175,920	(1.8)%	$	886,281	$	876,657	1.1%

PSE's revenues and associated expenses are not generated evenly throughout the year, primarily due to seasonal weather patterns, varying wholesale prices for electricity and the amount of hydroelectric energy supplies available to PSE, which make quarter-to-quarter comparisons difficult. Weather conditions in PSE's service territory have an impact on customer energy usage ~~affecting~~and affect PSE's billed revenue and energy supply expenses. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and also month to month within a season, primarily as result of weather conditions. PSE normally experiences its highest retail energy sales, and ~~subsequently often~~corresponding higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales and ~~subsequently~~corresponding lower power costs in the third quarter of the year. 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 for electric and natural gas operations are expected to normalize the impact of weather on operating revenue and net income. Under the decoupling mechanism, the Washington Commission allows 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 residential, commercial and industrial customers. For additional information, see Business, "Regulation and Rates" included in Item 1 of this report and Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Capital Expenditures

The following tables present PSE's capital expenditures for the five-year period ended December 31, ~~2016,~~2019, and gross utility plant by category and percentages ~~for the year ended~~as of December 31, ~~2016:~~2019:


Utility Plant Additions/Retirements 5-Year Total	2015 - 2019
(Dollars in Thousands)	Electric		Natural Gas		Common
Additions	$	1,804,920	$	1,083,353	$	763,244
Retirements	(826,478)		(112,983)		(204,220)
Net Utility Plant	$	978,442	$	970,370	$	559,024

Utility Plant Additions/Retirements 5-Year Total 2012-2016
(Dollars in Thousands) Electric Natural Gas Common
Additions $2,916,114 $758,141 $349,578
Retirements (453,220) (98,317) (254,106)
Net Utility Plant $2,462,894 $659,824 $95,472


Utility Plant Balance	December 31, 2019
(Dollars in Thousands)	Electric					Natural Gas				Common
Distribution	$	4,187,582	39.2%	$	3,998,120	89.3%	$	—	—%
Generation	3,740,762		35.1	2,731		0.1	—		—
Transmission	1,571,186		14.7	—		—	—		—
General Plant & Other	1,171,798		11.0	477,197		10.7	1,121,568		100
Total	$	10,671,328	100.0%	$	4,478,048	100.0%	$	1,121,568	100%

Utility Plant Balance December 31, 2016
(Dollars in Thousands) Electric Natural Gas Common
Distribution $3,587,449 36.5% $3,329,151 91.4% $— —%
Generation 4,118,431 42.0 6,737 0.2 — —
Transmission 1,420,334 14.5 — — — —
General Plant & Other 686,955 7.0 304,383 8.4 632,718 100.0
Total $9,813,169 100.0% $3,640,271 100.0% $632,718 100.0%

Employees

At December 31, ~~2016,~~2019, PSE had approximately ~~3,000~~3,130 full-time equivalent employees. Approximately ~~1,100~~1,020 PSE employees are represented by the International Brotherhood of Electrical Workers Union (IBEW) ~~and~~or the United Association of Plumbers and Pipefitters (UA). The ~~current~~ contracts with the IBEW and the UA were both ratified effective December 2017, and will expire on March 31, ~~2017~~2020, and September 30, ~~2017,~~2021, respectively.

Puget Energy does not have any employees. PSE's employees provide employment services to Puget Energy and charges for their related salaries and benefits at cost.

~~Segment Information~~

Puget Energy operates one reportable business segment referred to as the regulated utility segment. For more information on this segment, see Note 17, "Segment Information" to the consolidated financial statements included in item 8 of this report.

Corporate Location

PSE’s and Puget Energy's principal executive offices are located at ~~10885~~355 110th Ave NE, 4^th ~~Street, Suite 1200,~~ Bellevue, Washington 98004 and the telephone number is (425) 454-6363.

Available Information

The Company’s reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available or may be accessed free of charge at the Company’s website, www.pugetenergy.com. The Securities and Exchange Commission (SEC) maintains an internet site that contains reports, proxy and information ~~required by Item 101(e) of Regulation S-K is incorporated herein by reference to~~statements, and other information regarding issuers that file electronically with the ~~material under “Additional Information” in Part III Item 10, "Directors, Executive Officers~~SEC and ~~Corporate Governance".~~information may also be obtained via the SEC Internet website at www.sec.gov.

Regulation and Rates

PSE is subject to the regulatory authority of: (i) the FERC with respect to the transmission of electricity, the sale of electricity at wholesale, accounting and certain other matters; and (ii) the Washington Commission as to retail rates, accounting, the issuance of securities and certain other matters. PSE also must comply with mandatory electric system reliability standards developed by the North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC, whose standards are enforced by the Western Electricity Coordinating Council (WECC) in PSE’s operating territory.

~~2013 Expedited Rate Filing, Decoupling and Centralia Decision~~

PSE filed a settlement agreement 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 includes the property tax tracker. 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% to 7.77% to update long- term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan (K-Factor) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was to be filed before April 1, 2016 and was later extended to January 17, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.

Rate mechanisms include: (i) trackers that typically track specific costs during the previous ~~12-month~~twelve-month period and (ii) riders that project cost recovery during a ~~forward looking 12-month~~forward-looking twelve-month period. Both allow recovery of expenditures ~~without~~outside the ~~lengthy~~ process of a full ~~GRC.~~general rate case (GRC).

The following table shows PSE’s rate filings for its trackers and riders and whether or not they are included in decoupling rates:



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

General Rate Case Filing

On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in Colstrip, Montana (Colstrip) Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC.

~~On January 13, 2017,~~ PSE filed ~~its~~a GRC with the Washington Commission ~~which proposed a weighted cost~~on June 20, 2019, requesting an overall increase in electric and natural gas rates of ~~capital of 7.74%~~6.9% and 7.9%, ~~or 6.69% after-tax, and a capital structure of 48.5% in common equity with~~respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years.On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in our original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed.On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%.The requested ~~combined~~rate increase for both electric ~~tariff changes would result~~and natural gas remained at 6.9% and 7.9%, respectively. For both electric and

natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a ~~net~~reduction in the electric rate increase of ~~$86.3~~only $1.5 million ~~or 4.1%. The requested combined~~and did not have an impact on the natural gas ~~tariff changes would result~~rate increase.

For further details regarding the 2019 GRC filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in ~~a net decrease~~Item 8 of ~~$22.3 million, or 2.4%. The filing was subsequently suspended, which means that~~this report.

Expedited Rate Filing

On November 7, 2018, PSE filed an ERF with the ~~final rates granted~~Washington Commission. On January 22, 2019, all parties in the proceeding ~~will go~~reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

For further details regarding the 2018 ERF filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.

Washington Commission Tax Deferral Filing

The TCJA was signed into ~~effect no later than~~law in December ~~13,~~ 2017.

~~PSE’s GRC filing included~~ As a result of this change, PSE re-measured its deferred tax balances under the ~~required plan~~new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for ~~Colstrip Units 1~~the impacts of tax reform. The deferred accounting treatment results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and 2 closures, see Item 3, "Legal Proceedings". Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a general rate case proceeding. PSE also requested approval to establish an electric CRM similar to its existing natural gas ~~CRM which would allow PSE~~customers associated with TCJA to ~~obtain accelerated cost recovery on specified electric reliability projects.~~reflect the decrease in the federal corporate income tax rate from 35% to 21%. Other outcomes associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures.

Decoupling Filings

~~The~~While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs and beginning December 19, 2017, fixed production costs from most residential, commercial and industrial customers. This monthly adjustment mitigates the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, ~~these~~ electric and natural gas delivery revenues ~~will be~~are recovered on a per customer basis and electric fixed production energy costs are recovered on the basis of a fixed monthly amount regardless of actual consumption levels. The energy supply costs, which are part of the power cost adjustment (PCA) and purchased gas adjustment (PGA) mechanisms, are not included in the decoupling mechanism. ~~The~~Total electric and natural gas revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual ~~consumption.~~consumption except for fixed production costs, which are held at the level of cost from the most recent rate proceeding and are not impacted by customer growth. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. ~~The allowed~~For further details regarding decoupling ~~revenue per customer for~~filings, see Note 4, "Regulation and Rates" to the ~~recovery~~consolidated financial statements included in Item 8 of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requested mechanism is approved in PSE’s 2017 GRC which PSE filed on January 13, 2017. Decoupling over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended.this report.

Electric RateFilings

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” islevels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached.

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

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

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

Annual Power Cost Variability Company's Share Customers’ Share
Over or Under Collection: Over Under Over Under
Over or Under Collected by up to $17 million 100% 100% —% —%
Over or Under Collected by between $17 million - $40 million 35 50 65 50
Over or Under Collected beyond $40 + million 10 10 90 90

~~The settlement also resulted~~scale is used in ~~the following changes to~~ the PCA mechanism:

~~Reduction~~


	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

Power Cost Adjustment Clause Filing

The Power Cost Adjustment Clause filing reflects the transition fee as required by Section 12 of the Microsoft Special Contract.

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 compared to the ~~cumulative deferral trigger~~forecasted load set in rates.

Electric Property Tax Tracker Mechanism

~~Removal~~recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of ~~fixed production costs~~property taxes assessed. The tracker is adjusted each year in May based on that year's assessed property taxes and true-up from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;prior year.

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

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

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

PSE had an annual PCA receivable during the year ended December 31, 2016, due to under recovering $1.0 million of power costs. This compares to an annual PCA receivable of $8.7 million for the year ended December 31, 2015. The change was driven by a decrease in actual costs.

Federal Incentive Tracker Tariff

The Federal Incentive Tracker Tariff passes through to customers the benefits associated with ~~realized~~the wind-related treasury ~~grants and PTCs.~~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~~federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. Rates change annually on January 1. Additionally, this tracker is impacted by the TCJA previously discussed. Accordingly, PSE filed for a one-time rate change to be effective May 1, 2018, to recognize the decrease in the federal corporate income tax rate from 35% to 21%.

Residential Exchange Benefit

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

Power Cost Only Rate Case

A power cost rate case (PCORC) 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.

~~Electric Property Tax Tracker~~

Natural Gas Rate Filings

Natural Gas Cost Recovery Mechanism

The purpose of the ~~property tax tracker~~cost recovery mechanism (CRM) is to ~~pass through~~recover capital costs related to projects included in PSE's pipe replacement program plan on file with the ~~cost~~Washington Commission with the intended effect of ~~all property taxes incurred by~~enhancing the ~~Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After~~safety of 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.

~~Electric Conservation Rider~~

~~The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation.~~natural gas distribution system. 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.November 1.

~~Natural Gas Rate Filings~~

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.

~~Cost Recovery Mechanism~~

~~The purpose~~ Rates typically change annually on November 1, although out-of-cycle rate changes are allowed at other times 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.year if needed.

Natural Gas Property Tax Tracker Mechanism

The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker ~~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 natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual ~~versus~~compared to forecast conservation expenditures from the prior year, as well as actual ~~load being different than~~compared to the forecasted load set in rates.

For additional information on electric and natural gas rates, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this ~~report and Note 3, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this~~ report.

ELECTRIC UTILITY OPERATING STATISTICS


	Year Ended December 31,										Year Ended December 31,
	2016			2015			2014				2019		2018		2017
Generation and purchased power, MWh										Generation and purchased power, MWh
Company-controlled resources	11,577,608			12,747,014			11,640,504			Company-controlled resources	13,420,043		11,168,286		10,825,778
Contracted resources	7,023,786			5,911,012			4,050,062			Contracted resources	6,752,261		7,654,872		8,337,348
Non-firm energy purchased	6,005,797			5,315,266			8,001,425			Non-firm energy purchased	5,707,102		6,490,602		6,147,778
Total generation and purchased power	24,607,191			23,973,292			23,691,991			Total generation and purchased power	25,879,406		25,313,760		25,310,904
Less: losses and Company use	(1,547,619		)	(1,514,272		)	(1,724,501		)	Less: losses and Company use	(1,298,854)		(1,513,451)		(1,568,599)
Total energy sales, MWh	23,059,572			22,459,020			21,967,490			Total energy sales, MWh	24,580,552		23,800,309		23,742,305
Electric energy sales, MWh										Electric energy sales, MWh
Residential	10,245,326			10,164,703			10,349,928			Residential	10,756,628		10,497,389		10,931,999
Commercial	8,895,950			8,999,068			8,900,863			Commercial	8,837,457		8,932,681		9,089,842
Industrial	1,223,214			1,257,958			1,226,588			Industrial	1,161,149		1,189,828		1,214,818
Other customers	90,753			94,847			98,499			Other customers	85,302		84,382		87,230
Total energy sales to customers	20,455,243			20,516,576			20,575,878			Total energy sales to customers	20,840,536		20,704,280		21,323,889
Sales to other utilities and marketers	2,604,329			1,942,444			1,391,612			Sales to other utilities and marketers	3,740,016		3,096,029		2,418,416
Total energy sales, MWh	23,059,572			22,459,020			21,967,490			Total energy sales, MWh	24,580,552		23,800,309		23,742,305
Transportation, including unbilled	2,085,574			2,012,827			2,099,219			Transportation, including unbilled	2,322,021		2,028,727		2,001,244
Electric energy sales and transportation, MWh	25,145,146			24,471,847			24,066,709			Electric energy sales and transportation, MWh	26,902,573		25,829,036		25,743,549
Electric operating revenue by classes										Electric operating revenue by classes
(Dollars in Thousands)										(Dollars in Thousands)
Residential	$	1,138,871		$	1,061,117		$	1,003,205		Residential	$	1,139,356	$	1,147,260	$	1,232,075
Commercial	872,057			867,786			824,778			Commercial	854,910		885,457		892,360
Industrial	113,469			114,223			107,750			Industrial	105,020		110,607		112,817
Other customers	20,045			20,216			19,707			Other customers	18,408		18,718		19,729
Total operating revenue from customers	2,144,442			2,063,342			1,955,440			Total operating revenue from customers	2,117,694		2,162,042		2,256,981
Transportation, including unbilled	10,937			10,143			9,502			Transportation, including unbilled	19,512		13,878		12,584
Sales to other utilities and marketers	50,124			46,666			41,680			Sales to other utilities and marketers	109,105		89,324		53,789
Decoupling revenue	29,968			13,630			25,735			Decoupling revenue	15,673		13,530		9,975
Other decoupling revenue¹	(21,168		)	(16,634		)	5,609			Other decoupling revenue¹	(6,866)		(5,475)		(27,706)
Miscellaneous operating revenue	24,189			11,321			45,831			Miscellaneous operating revenue	241,923		182,620		115,040
Total electric operating revenue	$	2,238,492		$	2,128,468		$	2,083,797		Total electric operating revenue	$	2,497,041	$	2,455,919	$	2,420,663
Number of customers served (average):										Number of customers served (average):
Residential	984,739			970,830			960,708			Residential	1,025,024		1,010,574		998,078
Commercial	125,067			123,072			121,332			Commercial	129,944		128,845		126,829
Industrial	3,425			3,434			3,437			Industrial	3,328		3,362		3,399
Other	6,472			6,283			6,023			Other	7,323		6,992		6,722
Transportation	16			16			17			Transportation	80		16		16
Total customers	1,119,719			1,103,635			1,091,517			Total customers	1,165,699		1,149,789		1,135,044

_______________


¹	~~Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.~~

^1.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

ELECTRIC UTILITY OPERATING STATISTICS (Continued)


	Year Ended December 31,										Year Ended December 31,
	2016			2015			2014				2019			2018			2017
Average kWh used per customer:										Average kWh used per customer:
Residential	10,404			10,470			10,773			Residential	10,494			10,388			10,953
Commercial	71,129			73,120			73,360			Commercial	68,010			69,329			71,670
Industrial	357,143			366,324			356,877			Industrial	348,903			353,905			357,404
Other	14,022			15,096			16,354			Other	11,649			12,068			12,977
Average revenue per customer:										Average revenue per customer:
Residential	$	1,157		$	1,093		$	1,044		Residential	$	1,112		$	1,135		$	1,234
Commercial	6,973			7,051			6,798			Commercial	6,579			6,872			7,036
Industrial	33,130			33,262			31,350			Industrial	31,556			32,899			33,191
Other	3,097			3,218			3,272			Other	2,514			2,677			2,935
Average retail revenue per kWh sold:										Average retail revenue per kWh sold:
Residential	$	0.1112		$	0.1044		$	0.0969		Residential	$	0.1059		$	0.1093		$	0.1127
Commercial	0.0980			0.0964			0.0927			Commercial	0.0967			0.0991			0.0982
Industrial	0.0928			0.0908			0.0878			Industrial	0.0904			0.0930			0.0929
Other	0.2209			0.2131			0.2001			Other	0.2158			0.2218			0.2262
Average retail revenue per kWh sold	$	0.1048		$	0.1006		$	0.0950		Average retail revenue per kWh sold	$	0.1016		$	0.1044		$	0.1058
Heating degree days	3,823			3,800			3,829			Heating degree days	4,208			4,065			4,584
Percent of normal - NOAA¹30-year average	81.0		%	80.5		%	81.2		%
Load factor²	56.2		%	56.2		%	52.3		%
Percent of normal - NOAA² 30-year average										Percent of normal - NOAA² 30-year average	89.6		%	86.2		%	97.2		%
Load factor³										Load factor³	61.6		%	64.2		%	51.6		%

_______________


¹	~~National Oceanic and Atmospheric Administration (NOAA).~~


²	~~Average megawatt (aMW) usage by customers divided by their maximum usage.~~

^2.National Oceanic and Atmospheric Administration (NOAA).

^3.Average megawatt (aMW) usage by customers divided by their maximum usage.

Electric Supply

At December 31, ~~2016,~~2019, PSE’s electric power resources, which include company-owned or controlled resources as well as those under long-term contract, had a total capacity of approximately ~~4,844~~4,733 megawatts (MW). PSE’s historical peak load of approximately 4,912 MW occurred on December 10, 2009. In order to meet an extreme winter peak load, PSE may supplement its electric power resources with winter-peaking call options and other instruments. When it is more economical for PSE to purchase power than to operate its own generation facilities, PSE will purchase spot market energy when sufficient transmission capacity is available.

The following table shows PSE’s electric energy supply resources and energy production for the years ended December 31, ~~2016~~2019, and ~~2015:~~

2018:


	Peak Power Resources At December 31,						Energy Production At December 31,
`													`	Peak Power Resources At December 31,							Energy Production At December 31,
	2016			2015			2016			2015				2019			2018			2019		2018
	MW	%		MW	%		MWh	%		MWh	%			MW	%	MW	%	MWh	%	MWh	%
Purchased resources:													Purchased resources:
Columbia River PUD contracts	708	14.6	%	708	14.5	%	3,371,827	13.7	%	3,325,450	13.9	%
Columbia River PUD contracts¹													Columbia River PUD contracts¹	687	14.5%	674	14.3%	2,642,177	10.2%	3,468,702	13.7%
Other hydroelectric	79	1.6		85	1.7		365,670	1.5		179,057	0.7		Other hydroelectric	72	1.5	72	1.5	272,653	1.0	315,948	1.2
Other producers	387	8.0		463	9.5		2,999,171	12.1		2,200,098	9.2		Other producers	285	6.0	284	6.2	3,276,502	12.7	3,406,627	13.6
Wind	56	1.2		56	1.1		138,148	0.6		130,777	0.5		Wind	56	1.2	56	1.2	123,368	0.5	131,270	0.5
Short-term wholesale energy purchases	N/A	—		N/A	—		6,154,767	25.0		5,390,896	22.5		Short-term wholesale energy purchases	N/A	—	N/A	N/A	6,144,663	23.7	6,822,927	26.9
Total purchased	1,230	25.4	%	1,312	26.8	%	13,029,583	52.9	%	11,226,278	46.8	%	Total purchased	1,100	23.2%	1,086	23.2%	12,459,363	48.1%	14,145,474	55.9%
Company-controlled resources:													Company-controlled resources:
Hydroelectric	254	5.2	%	254	5.2	%	933,522	3.8	%	706,231	2.9	%	Hydroelectric	250	5.3%	250	5.3%	712,727	2.8%	914,540	3.6%
Coal	677	14.0		677	13.9		4,529,179	18.4		4,495,032	18.8
Coal³													Coal³	677	14.3	677	14.4	4,347,639	16.8	4,184,950	16.5
Natural gas/oil	1,908	39.4		1,871	38.3		4,152,205	16.9		5,830,318	24.3		Natural gas/oil	1,931	40.8	1,908	40.6	6,692,188	25.9	4,152,359	16.4
Wind	773	16.0		773	15.8		1,962,702	8.0		1,715,433	7.2		Wind	773	16.3	773	16.5	1,667,489	6.4	1,932,378	7.6
Other¹	2	—		—	—		—	—		—	—
Other²													Other²	2	—	2	—	—	—	—	—
Total company-controlled	3,614	74.6	%	3,575	73.2	%	11,577,608	47.1	%	12,747,014	53.2	%	Total company-controlled	3,633	76.8%	3,610	76.8%	13,420,043	51.9%	11,184,227	44.1%
Total resources	4,844	100.0	%	4,887	100.0	%	24,607,191	100.0	%	23,973,292	100.0	%	Total resources	4,733	100.0%	4,696	100.0%	25,879,406	100.0%	25,329,701	100.0%

_______________


¹	~~It is estimated that the Glacier Battery Storage has delivered approximately 250,000 Kilowatt Hour (kWh) since the end of September 2016.~~

1.Net of 35 MW and 33 MW capacity delivered to Canada pursuant to the provisions of a treaty between Canada and the United States and Canadian Entitlement Allocation agreements as of December 31, 2019, and 2018, respectively.

2.It is estimated that the Glacier Battery Storage has delivered approximately 1,468.2 and 1,362.7 MWh as of December 31, 2019, and 2018, respectively.

3.In July 2016, PSE reached a settlement with the Sierra Club to retire Colstrip Units 1 and 2 no later than July 1, 2022. Colstrip Units 1 and 2, 307 MW Net Maximum Capacity were retired effective December 31, 2019.

Company–Owned Electric Generation Resources

At December 31, ~~2016,~~2019, PSE owns the following plants with an aggregate net generating capacity of ~~3,614~~3,633 MW:

Plant Name

Plant Type

Net Maximum

Capacity (MW)¹

Year Installed

Plant Name

Plant Type

Net Maximum

Capacity (MW)¹

Year Installed

Colstrip Units 3 & 4 (25% interest)

Coal

370

1984 & 1986

Colstrip Units 3 & 4 (25% interest)

Coal

370

1984 & 1986

Colstrip Units 1 & 2 (50% interest)²

Coal

307

1975 & 1976

Colstrip Units 1 & 2 (50% interest)²

Coal

307

1975 & 1976

Mint Farm

Natural gas combined cycle

297

2007; acquired 2008

Mint Farm

Natural gas combined cycle

320

2007; acquired 2008; upgraded 2017

Goldendale

Natural gas combined cycle

315

2004; acquired 2007; upgraded 2016

Goldendale

Natural gas combined cycle

315

2004, acquired 2007, upgraded 2016

Frederickson Unit 1 (49.85% interest)

Natural gas combined cycle

136

2002; added duct firing in 2005

Frederickson Unit 1 (49.85% interest)

Natural gas combined cycle

136

2002; added duct firing 2005

Lower Snake River

Wind

343

2012

Lower Snake River

Wind

343

2012

Wild Horse

Wind

273

2006 & 2009

Wild Horse

Wind

273

2006 & 2009

Hopkins Ridge

Wind

157

2005 & 2008

Hopkins Ridge

Wind

157

2005 & 2008

Fredonia Units 1 & 2

Dual-fuel combustion turbines

207

1984

Fredonia Units 1 & 2

Dual-fuel combustion turbines

207

1984

Frederickson Units 1 & 2

Dual-fuel combustion turbines

149

1981

Frederickson Units 1 & 2

Dual-fuel combustion turbines

149

1981

Whitehorn Units 2 & 3

Dual-fuel combustion turbines

149

1981

Whitehorn Units 2 & 3

Dual-fuel combustion turbines

149

1981

Fredonia Units 3 & 4

Dual-fuel combustion turbines

107

2001

Fredonia Units 3 & 4

Dual-fuel combustion turbines

107

2001

Ferndale

Natural gas co-generation

253

1994; acquired 2012

Ferndale

Natural gas co-generation

253

1994; acquired 2012

Encogen

Natural gas co-generation

165

1993; acquired 1999

Encogen

Natural gas co-generation

165

1993; acquired 1999

Sumas

Natural gas co-generation

127

1993; acquired 2008

Sumas

Natural gas co-generation

127

1993; acquired 2008

Upper Baker River

Hydroelectric

1959

Upper Baker River

Hydroelectric

1959; unit 2 upgraded 1997

Lower Baker River

Hydroelectric

109

1925; reconstructed 1960; upgraded 2001 and 2013

Lower Baker River

Hydroelectric

105

1925: reconstructed 1960; upgraded 2001 and 2013

Snoqualmie Falls³

Hydroelectric

1898 to 1911 & 1957; rebuilt 2013

Snoqualmie Falls³

Hydroelectric

1898 to 1911 & 1957; rebuilt 2013

Crystal Mountain

Internal combustion

1969

Crystal Mountain

Internal combustion

1969

Glacier Battery Storage

Lithium Iron Phosphate

2016

Glacier Battery Storage

Lithium Iron Phosphate

2016

Total net capacity

3,614

Total Net Capacity

3,633

_______________


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.~~

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. Colstrip Units 1 and 2 were retired effective December 31, 2019.

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.

Columbia River Electric Energy Supply Contracts

During ~~2016~~,2019, approximately ~~13.7%~~10.2% of PSE’s energy supply ~~requirement~~ was obtained through long-term contracts with three Washington Public Utility Districts (PUDs) that own and operate hydroelectric projects on the Columbia River (Mid-Columbia). ~~PSE agrees to pay a share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to its share of projected output.~~ PSE’s payments are not contingent upon the projects being operable.

As of December 31, ~~2016, PSE was entitled to purchase portions~~2019, PSE's portion of the power output of the PUDs’ projects asare set forth below:


			Company’s Annual Share (Approximate)
Project	Contract Expiration Year	License Expiration Year	Percent of Output		MW Capacity
Chelan County PUD:
Rock Island Project	2031	2029	25.0	%	156
Rocky Reach Project	2031	2052	25.0		325
Douglas County PUD:
Wells Project	2028	2052	27.1		228
Grant County PUD:
Priest Rapids Development	2052	2052	0.6		6
Wanapum Development	2052	2052	0.6		7
Total					722

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

Other Electric Supply, Exchange and Transmission Contracts and Agreements

PSE purchases electric energy under long-term firm purchased power contracts with other utilities and marketers in the Western region. PSE is generally not obligated to make payments under these contracts unless power is delivered. PSE has seasonal energy and capacity exchange agreements with the Bonneville Power Administration (BPA) for 44 aMW of capacity which expires on July 1, 2017 with no provision to renew this agreement. PSE will procure more capacity from Mid-Columbia to recover for this loss of capacity, if needed. PSE also has an agreement with Pacific Gas & Electric Company (PG&E) for 300 MW of seasonal capacity exchange which currently has no set expiration. PG&E filed for bankruptcy on January 29, 2019. As of December 31, 2019, there was no outstanding obligation due from PG&E related to the energy exchange contract, an agreement in place to supplement peak loads through the transmission of energy from PG&E to PSE in the winter months and from PSE to PG&E in the summer months. During and since emerging from its 2001-2004 bankruptcy proceedings, PG&E delivered on the energy exchange contract and has continued to meet the exchange contract through its current bankruptcy proceedings.

PSE began participating in the Energy Imbalance Market (EIM) operated by the California Independent System Operator on October 1, 2016. PSE has committed 450 MW of existing BPA transmission solely for the EIM market. Participation ~~is expected to reduce~~has resulted in reduced costs for PSE customers ~~enhance~~of approximately $16.2 million per annum, enhanced system reliability, ~~integrate~~integration of variable energy resources, and ~~leverage~~ geographic diversity of electricity demand and generation resources. The calculated benefits represent the annual cost savings of the EIM dispatch compared with a counter-factual dispatch without the EIM. Benefits can take the form of cost savings or profits or their combination. Benefits include greenhouse gas (GHG) revenue, transfer revenues and flexible ramping revenues.

PSE has entered into multiple various-term transmission contracts with other utilities to integrate electric generation and contracted resources into PSE’s system. These transmission contracts require PSE to pay for transmission service based on the contracted MW level of demand, regardless of actual use. Other transmission agreements provide actual capacity ownership or capacity ownership rights. PSE’s annual charges under these agreements are also based on contracted MW volumes. Capacity on these agreements that is not committed to serve PSE’s load is available for sale to third parties. PSE also purchases short-term transmission services from a variety of providers, including the BPA.

In ~~2016~~,2019, PSE had ~~4,646~~4,797 MW and ~~695~~595 MW of total transmission demand contracted with the BPA and other utilities, respectively. PSE’s remaining transmission capacity needs are met via PSE owned transmission assets.

Natural Gas Supply for Electric Customers

PSE purchases natural gas supplies for its power portfolio to meet electrical demand ~~for its combustion turbine generators.~~through gas-fired generation. Supplies range from long-term to daily agreements, as ~~the demand for the turbines~~turbine fueling varies depending on market heat rates. Purchases are made from a diverse group of major and independent natural gas producers and marketers in the United States and Canada. PSE also enters into financial hedges to manage the cost of natural gas. PSE utilizes natural gas storage capacity and transportation that is dedicated to and paid for by the power portfolio to facilitate increased natural gas supply reliability and intra-day dispatch of PSE’s natural gas-fired generation resources. ~~During 2016, approximately 64.0% of natural gas purchased for the power portfolio originated in British Columbia, 20.0% in Alberta and 16.0% in the United States.~~

Integrated Resource Plans, Resource Acquisition and Development

PSE is required by Washington Commission regulations to file an electric and natural gas integrated resource plan (IRP) every two years. ~~The 2015~~However, the governor signed HB 5116, the Clean Energy Transformation Act (CETA), into law on May 7, 2019. As a result, the 2019 IRP was suspended and a progress report was filed on November ~~30, 2015~~15, 2019. Although the 2019 IRP process was suspended, a resource need was identified, but there was no final resource portfolio to identify cost effective conservation. Based on 2019 IRP resource need projections and ~~identified~~conservation projections from the ~~following~~2017 IRP, the capacity ~~needs:~~shortfalls and surpluses are:

2017 2018 2019 2020 2021
Projected MW shortfall/(surplus) (28) (43) (44) (71) 275


	2020	2021	2022	2023
Projected MW shortfall/(surplus)	539	519	462	491

PSE projects its future energy needs will exceed current resources in its supply portfolio beginning in 2020 because of the retirement of Colstrip Units 1 and 2. Colstrip 1 and 2 were retired effective December 31, 2019, and decreased capacity by approximately 307 MW per year. The expected capacity needs reflect the mix of energy efficiency programs deemed cost effective in the ~~2015~~2017 IRP. ~~In 2015,~~As part of the CETA, PSE ~~renewed all~~must achieve sales with renewable or non-emitting resources of at least 80% by 2030 and 100% by 2045. The 2021 IRP will fully explore the ~~Mid-Columbia transmission available for renewal during~~implementation of the ~~year to meet peak capacity needs.~~

CETA. PSE projects that beginning in 2021 its future energy needs will exceed current resources in its supply portfolio. The IRP identifies declining regional surpluses, requiring replacement of supplies to meet projected demands. Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs andis currently pursuing ~~additional renewable resources (primarily wind) and additional base load natural gas-fired generation~~resource acquisitions to meet the growing needs of its customers. If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the wholesale market, subject to the sharing bands of the PCA mechanism, at a cost that could, in the absence of regulatory relief, increase its expenses and reduce earnings and cash flows. The IRP will be updated in 2017 and is expected to be filed July 15, 2017.current capacity shortfall projections.

NATURAL GAS UTILITY OPERATING STATISTICS


										Year Ended December 31,
	Year Ended December 31,									2019		2018		2017
	2016			2015			2014
Natural gas operating revenue by classes (dollars in thousands):
Natural gas operating revenue by classes (Dollars in Thousands):									Natural gas operating revenue by classes (Dollars in Thousands):
Residential	$	578,955		$	597,572		$	644,055	Residential	$	613,617	$	598,923	$	686,438
Commercial firm	213,138			239,849			252,235		Commercial firm	218,302		219,390		251,584
Industrial firm	17,753			21,533			23,887		Industrial firm	15,698		17,247		20,077
Interruptible	24,447			29,082			30,770		Interruptible	18,381		21,113		24,317
Total retail natural gas sales	834,293			888,036			950,947		Total retail natural gas sales	865,998		856,673		982,416
Transportation services	20,322			18,666			17,069		Transportation services	20,283		19,984		21,718
Decoupling revenue	52,114			51,981			29,116		Decoupling revenue	2,296		6,115		3,522
Other decoupling revenue¹	(28,761		)	(26,038		)	2,208		Other decoupling revenue¹	(29,737)		(37,022)		(22,862)
Other	12,542			14,904			13,520		Other	16,531		4,998		12,965
Total natural gas operating revenue	$	890,510		$	947,549		$	1,012,860	Total natural gas operating revenue	$	875,371	$	850,748	$	997,759
Number of customers served (average):									Number of customers served (average):
Residential	749,586			737,339			727,244		Residential	782,413		772,130		761,010
Commercial firm	54,992			54,646			54,328		Commercial firm	56,113		55,716		55,372
Industrial firm	2,371			2,378			2,383		Industrial firm	2,304		2,308		2,330
Interruptible	410			429			449		Interruptible	367		393		398
Transportation	227			221			208		Transportation	230		234		226
Total customers	807,586			795,013			784,612		Total customers	841,427		830,781		819,336
Natural gas volumes, therms (thousands):									Natural gas volumes, therms (thousands):
Residential	521,771			492,997			527,423		Residential	605,313		571,265		621,915
Commercial firm	233,586			230,507			242,095		Commercial firm	277,639		264,775		279,656
Industrial firm	22,783			23,777			26,481		Industrial firm	22,915		23,890		25,500
Interruptible	49,533			43,931			46,113		Interruptible	45,176		47,275		49,249
Total retail natural gas volumes, therms	827,673			791,212			842,112		Total retail natural gas volumes, therms	951,043		907,205		976,320
Transportation volumes	230,724			220,392			211,429		Transportation volumes	227,657		230,735		236,578
Total volumes	1,058,397			1,011,604			1,053,541		Total volumes	1,178,700		1,137,940		1,212,898

_______________


¹	~~Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.~~

^1.Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.

NATURAL GAS UTILITY OPERATING STATISTICS (Continued)


	Year Ended December 31,
	2019			2018			2017
Working natural gas volumes in storage at year end, therms (thousands):
Jackson Prairie	82,892			76,348			86,051
Clay Basin	77,532			74,420			45,854

Average therms used per customer:
Residential	774			740			817
Commercial firm	4,948			4,752			5,050
Industrial firm	9,946			10,351			10,944
Interruptible	123,095			120,293			123,742
Transportation	989,813			986,045			1,046,806
Average revenue per customer:
Residential	$	784		$	776		$	902
Commercial firm	3,890			3,938			4,544
Industrial firm	6,813			7,473			8,617
Interruptible	50,084			53,724			61,098
Transportation	88,187			85,400			96,099
Average revenue per therm sold:
Residential	$	1.014		$	1.048		$	1.104
Commercial firm	0.786			0.829			0.900
Industrial firm	0.685			0.722			0.787
Interruptible	0.407			0.447			0.494
Average retail revenue per therm sold	$	0.911		$	0.944		$	1.006
Transportation	0.089			0.087			0.092
Heating degree days	4,208			4,065			4,584
Percent of normal - NOAA 30-year average	89.6		%	86.2		%	97.2		%

Year Ended December 31,
2016 2015 2014
Working natural gas volumes in storage at year end, therms (thousands):

Jackson Prairie 86,374
78,337
81,889
Clay Basin 63,136
54,199
29,719
Plymouth 2,162
1,828
2,206
Average therms used per customer:
Residential 696
669
725
Commercial firm 4,248
4,218
4,456
Industrial firm 9,609
9,999
11,112
Interruptible 120,812
102,403
102,701
Transportation 1,016,406
997,249
1,016,486
Average revenue per customer:

Residential $ 772
$ 810
$ 886
Commercial firm 3,876
4,389
4,643
Industrial firm 7,488
9,055
10,024
Interruptible 59,626
67,791
68,530
Transportation 89,524
84,460
82,063
Average revenue per therm sold:

Residential $ 1.110
$ 1.212
$ 1.221
Commercial firm 0.912
1.041
1.042
Industrial firm 0.779
0.906
0.902
Interruptible 0.494
0.662
0.667
Average retail revenue per therm sold 1.008
1.122
1.129
Transportation 0.088
0.085
0.081
Heating degree days 3,823
3,800
3,829
Percent of normal - NOAA 30-year average 81.0 % 80.5 % 81.2 %

Natural Gas Supply for Natural Gas Customers

PSE purchases a portfolio of natural gas supplies ranging from long-term firm to daily from a diverse group of major and independent natural gas producers and marketers in the United States and Canada (British Columbia and Alberta). PSE also enters into physical and financial hedges to manage volatility in the cost of natural gas. All of PSE’s natural gas supply is ultimately transported through the facilities of Northwest Pipeline, GPLLC (NWP), the sole interstate pipeline delivering directly into PSE’s service territory. Accordingly, delivery of natural gas supply to PSE’s natural gas system is dependent upon the reliable operations of NWP.

At December 31,
2016 2015
Peak Firm Natural Gas Supply Dth per Day % Dth per Day %
Purchased natural gas supply:
British Columbia 290,200
30.7 % 210,000
23.4 %
Alberta 76,500
8.1
110,000
12.2
United States 115,600
12.2
118,100
13.1
Total purchased natural gas supply 482,300
51.0
438,100
48.7
Purchased storage capacity:
Jackson Prairie 48,400
5.1
48,400
5.4
Clay Basin 64,100
6.8
61,600
6.8
Total purchased storage capacity 112,500
11.9
110,000
12.2
Owned storage capacity:

Jackson Prairie 348,700
36.9
348,700
38.8
Propane and LNG 2,500
0.3
2,500
0.3
Total owned storage capacity 351,200
37.1
351,200
39.1
Total peak firm natural gas supply¹
946,000
100.0 % 899,300
100.0 %
Other and commitments with third parties (5,700 ) *
(6,200 ) *
Total net peak firm natural gas supply 940,300
*
893,100
*

~~_______________~~


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


*	~~Not meaningful and/or applicable.~~

For base load, peak management and supply reliability purposes, PSE supplements its firm natural gas supply portfolio by purchasing natural gas in periods of lower demand, injecting it into underground storage facilities and withdrawing it during ~~the peak winter heating season.~~periods of high demand or reduced supply. Underground storage facilities at Jackson Prairie in western Washington and at Clay Basin in Utah are used for this purpose. Clay Basin withdrawals are used to supplement purchases from the U.S. Rocky Mountain supply region, while Jackson Prairie provides incremental peak-day resources utilizing firm storage redelivery transportation capacity. Jackson Prairie is also used for daily balancing of load requirements on PSE’s natural gas system. Peaking needs are also met by using PSE-owned natural gas held in PSE’s LNG peaking facility located within its distribution system in Gig Harbor, Washington; as well as interrupting service to customers on interruptible service rates, if necessary.

PSE expects to meet its firm peak-day requirements for residential, commercial and industrial markets through its firm natural gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. PSE believes it will be able to acquire incremental firm natural gas supply and transportation capacity to meet anticipated growth in the requirements of its firm customers for the foreseeable future.

~~During 2016, approximately 56.0% of natural gas purchased by PSE for its natural gas customers originated in British Columbia, 21.0% originated in Alberta and 23.0% in the United States.~~ PSE’s firm natural gas supply portfolio has adequate flexibility in its transportation arrangements to enable it to achieve savings when there are regional price differentials between natural gas supply basins. The geographic mix of suppliers and daily, monthly and annual take requirements permit some degree of flexibility in managing natural gas supplies during periods of lower demand to minimize costs. Natural gas is marketed outside of PSE’s service territory (off-system sales) to optimize resources when on-system customer demand requirements permit and market economics are favorable; the resulting economics of these transactions are reflected in PSE’s natural gas customer tariff rates through the PGA mechanism.

Natural Gas Storage Capacity

PSE holds storage capacity in the Jackson Prairie and Clay Basin underground natural gas storage facilities adjacent to NWP’s pipeline to serve PSE’s natural gas customers. The Jackson Prairie facility is operated and one-third owned by PSE, and is used primarily for intermediate peaking purposes due to its ability to deliver a large volume of natural gas in a short time period. Combined with capacity contracted from NWP’s one-third stake in Jackson Prairie, PSE holds firm withdrawal capacity ~~in excess~~ of 453,800 Dekatherm (Dth) per day, and over 9.8 million Dth of storage capacity at the Jackson Prairie facility. Of this total, PSE ~~holds~~designates 397,100 Dth per day of the firm withdrawal capacity and over 9.2 million Dth of storage capacity ~~designated~~ to serve natural gas ~~customers, which represents nearly 42% of PSE's expected near-term peak-day requirement.~~customers. The location of the Jackson Prairie facility in PSE’s market area increases supply reliability and provides significant pipeline demand cost savings by reducing the amount of annual pipeline capacity required to meet peak-day natural gas requirements.

Of the remaining Jackson Prairie storage capacity, 56,700 Dth per day of firm withdrawal capacity and ~~641,000~~640,600 Dth of storage capacity is currently designated to PSE's power portfolio, increasing natural gas supply reliability and facilitating intra-day dispatch of PSE's natural gas-fired generation resources. In addition, PSE has temporarily released approximately 6,100 Dth per day of firm withdrawal capacity and 178,500 of Dth of storage capacity to a third party, in exchange for temporary firm pipeline capacity on a constrained portion of NWP's system.

The Clay Basin storage facility is a supply area storage facility that provides operational flexibility and price protection. PSE holds ~~over~~ 12.9 million Dth of Clay Basin storage capacity and approximately ~~107,000~~107,400 Dth per day of firm withdrawal capacity under two long-term contracts with remaining terms of one and three years and has rights to extend such agreements. PSE has temporarily released a portion of its Clay Basin storage services to third parties, and its net storage capacity and maximum firm withdrawal capacity at Clay Basin is 8.9 million Dth and over 74,000 Dth per day, respectively.

LNG and Propane-Air Resources

LNG and propane-air resources provide firm natural gas supply on short notice for short periods of time. Due to their typically high cost and slow cycle times, these resources are normally utilized as a last resort supply source in extreme peak-demand periods, typically during the coldest hours or days.

~~During 2014,~~ PSE ~~working with NWP determined that the pipeline redelivery service to PSE from NWP’s Plymouth LNG facility could no longer be considered firm during peak conditions. As~~holds a ~~result, PSE terminated the service agreement effective October 31, 2015 and removed the resource from its natural gas firm portfolio. In 2015, PSE and NWP negotiated a new~~ contract ~~for Plymouth LNG service for PSE’s generation fleet, which provides~~ for LNG storage services of 241,700 Dth of PSE-owned natural gas at Plymouth, with a maximum daily deliverability of 70,500 ~~Dth.~~Dth for use of the PSE ~~will use~~generation fleet. PSE uses the Plymouth contract as an alternate supply source for natural gas required to serve PSE’s generation fleet during peak periods on a daily or intra-day basis. In addition,

PSE ~~acquired~~holds 15,000 Dth/day of firm pipeline capacity from Plymouth for the generation fleet. The balance of the LNG capacity ~~will be~~is delivered using firm NWP pipeline transportation service previously acquired to serve PSE’s generation fleet.

PSE owns and operates the Swarr vaporized propane-air station located in Renton, Washington which includes storage capacity for approximately 1.5 million gallons of propane. This vaporized propane-air injection facility delivers the thermal equivalent of 10,000 Dth of natural gas per day for up to 12 days directly into PSE’s distribution ~~system,~~system; however, it is temporarily ~~not in-service~~out-of-service pending planned environmental ~~safety, efficiency~~ and reliability upgrades. PSE owns and operates an LNG peaking facility in Gig Harbor, Washington, with total capacity of 10,600 Dth, which is capable of delivering the equivalent of 2,500 Dth of natural gas per day.

~~Puget LNG LLC~~

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

Currently under construction at the Port of Tacoma, the Tacoma LNG facility is expected to be operational in ~~2019.~~2021. In January 2018, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, PSCAA's timing and decision on the air quality permit delayed the Company's construction schedule. In December 2019, PSCAA issued the air quality permit for the facility, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. When completed, the Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers, and provide LNG as fuel to transportation customers, particularly in the marine market. Pursuant to the Washington Commission’s order, ~~Puget LNG~~PSE will be allocated ~~57%~~43.0% of the capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility, and ~~PSE~~Puget LNG will be allocated the remaining ~~43%~~57.0% of the capital and operating costs. The portion of the Tacoma LNG facility allocated to PSE will be subject to regulation by the Washington Commission.

Natural Gas Transportation Capacity

PSE currently holds firm transportation capacity on pipelines owned by Cascade Natural Gas Company (CNGC), NWP, Gas Transmission Northwest (GTN), Nova Gas Transmission (NOVA), Foothills Pipe Lines (Foothills) and ~~Spectra's~~Enbridge Westcoast Energy (Westcoast). GTN, NOVA, and Foothills are all ~~TransCanada~~TC Energy Corporation companies. PSE pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of natural gas from receipt points to delivery points on such pipelines each day for the term or terms of the applicable agreements.

PSE holds approximately ~~543,000~~542,900 Dth per day of capacity for its natural gas customers on NWP that provides firm year-round delivery to PSE’s service territory. In addition, PSE holds approximately ~~447,000~~447,100 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored at Jackson ~~Prairie.~~Prairie to natural gas customers. PSE holds approximately ~~218,000~~217,900 Dth per day of firm transportation capacity on NWP to supply natural gas to its electric generating facilities. In addition, PSE holds over ~~34,000~~34,200 Dth per day of seasonal firm capacity on NWP to provide for delivery of natural gas stored in Jackson Prairie for its electric generating facilities. PSE’s firm transportation capacity contracts with NWP have remaining terms ranging from ~~two~~one to 2825 years. However, PSE has either the unilateral right to extend the contracts under the contracts’ current terms or the right of first refusal to extend such contracts under current FERC rules.

PSE’s firm transportation capacity for its natural gas customers on Westcoast’s pipeline is ~~132,000~~135,800 Dth per day under various contracts, with remaining terms of ~~two~~four to ~~four~~six years. PSE has other firm transportation capacity on Westcoast’s pipeline, which supplies the electric generating facilities, totaling ~~86,000~~88,400 Dth per day, with remaining terms of ~~two~~four to ~~four~~six years and an option for PSE to renew its rights under the Westcoast contract. PSE has firm transportation capacity for its natural gas customers on NOVA and Foothills pipelines, each totaling approximately ~~80,000~~79,000 Dth per day, with remaining terms of ~~two~~four to ~~seven~~six years and an option for PSE to renew its rights on the capacity on NOVA and Foothills pipelines. PSE has other firm transportation capacity on NOVA and Foothills pipelines, which supplies the electric generating facilities, each totaling approximately 41,000 Dth per day, with remaining ~~terms~~term of four ~~to seven~~ years. PSE’s firm transportation capacity for its natural gas customers on the GTN pipeline, totaling over 77,000 Dth per day, ~~has a~~with remaining term of ~~seven~~four years and PSE has a first right-of-refusal to extend such contracts under current FERC rules. PSE has other firm transportation capacity on GTN pipeline, which supplies the electric generating facilities, totaling ~~41,000~~40,600 Dth per day, with remaining terms of one to four years. PSE holds 259,000 decatherms per day of firm capacity on CNGC to ~~seven~~connect generating facilities to the pipeline grid with remaining terms of one to two years.

Capacity Release

The FERC regulates the release of firm pipeline and storage capacity for facilities which fall under its jurisdiction. Capacity releases allow shippers to temporarily or permanently relinquish unutilized capacity to recover all or a portion of the cost of such capacity. The FERC allows capacity to be released through several methods including open bidding and pre-arrangement. PSE has acquired some firm pipeline and storage service through capacity release provisions to serve its growing service territory and electric generation portfolio. PSE also mitigates a portion of the demand charges related to

unutilized storage and pipeline capacity through capacity release. Capacity release benefits derived from the natural gas customer portfolio are passed on to PSE’s natural gas customers through the PGA mechanism.

Energy Efficiency

PSE is required under Washington state law to pursue all available electric conservation that is cost-effective, reliable and feasible. PSE offers programs designed to help new and existing residential, commercial and industrial customers use energy efficiently. PSE uses a variety of mechanisms including cost-effective financial incentives, information and technical services to enable customers to make energy efficient choices with respect to building design, equipment and building systems, appliance purchases and operating practices. PSE recovers the actual costs of its electric and natural gas energy efficiency programs through rider mechanisms. However, the rider mechanisms do not provide assistance with gross margin erosion associated with reduced energy sales. To address this issue, PSE received approval in ~~2013~~2017 from the Washington Commission for continuation of electric and natural gas decoupling mechanisms, which mitigates gross margin erosion resulting from the Company's energy efficiency efforts.

Environment

PSE’s operations, including generation, transmission, distribution, service and storage facilities, are subject to environmental laws and regulations by federal, state and local authorities. See below for the primary areas of environmental law that have the potential to most significantly impact PSE’s operations and costs.

Air and Climate Change Protection

PSE owns numerous thermal generation facilities, including natural gas plants and an ownership percentage of Colstrip. All of these facilities are governed by the Clean Air Act (CAA), and all have CAA Title V operating permits, which must be renewed every five years. This renewal process could result in additional costs to the plants. PSE continues to monitor the permit renewal process to determine the corresponding potential impact to the plants. These facilities also emit greenhouse gases (GHG), and

thus are also subject to any current or future GHG or climate change legislation or regulation. The Colstrip plant represents PSE’s most significant source of GHG emissions.

Species Protection

PSE owns hydroelectric plants, wind farms and numerous miles of above ground electric distribution and transmission lines which can be impacted by laws related to species protection. A number of species of fish have been listed as threatened or endangered under the Endangered Species Act (ESA), which influences hydroelectric operations, and may affect PSE operations, potentially representing cost exposure and operational constraints. Similarly, there are a number of avian and terrestrial species that have been listed as threatened or endangered under the ESA or are protected by the Migratory Bird Treaty Act or the Bald and Golden Eagle Protection Act. Designations of protected species under these ~~two~~ laws have the potential to influence operation of our wind farms and above ground transmission and distribution systems.

Remediation

PSE and its predecessors are responsible for environmental remediation at various sites. These include properties currently and formerly owned by PSE (or its predecessors), as well as third-party owned properties where hazardous substances were allegedly generated, transported or released. The primary cleanup laws to which PSE is subject include the Comprehensive Environmental Response, Compensation and Liability Act (federal) and, in Washington, the Model Toxics Control Act (state). PSE is also subject to applicable remediation laws in the state of Montana for its ownership interest in Colstrip. These laws may hold liable any current or past owner or operator of a contaminated site, as well as any generator, transporter, arranger, or disposer of regulated substances.

Hazardous and Solid Waste and PCB Handling and Disposal

Related to certain operations, including power generation and transmission and distribution maintenance, PSE must handle and dispose of certain hazardous and solid wastes. These actions are regulated by the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (federal), the Toxic Substances Control Act (federal) and hazardous or dangerous waste regulations (state) that impose complex requirements on handling and disposing of regulated substances.

Water Protection

PSE facilities that discharge wastewater or storm water or store bulk petroleum products are governed by the Clean Water Act (federal and state) which includes the Oil Pollution Act amendments. This includes most generation facilities (and all of those with water discharges and some with bulk fuel storage), and many other facilities and construction projects depending on drainage, facility or construction activities, and chemical, petroleum and material storage.

Mercury Emissions

Mercury control equipment has been installed at Colstrip and has operated at a level that meets the current Montana requirement. Compliance, based on a rolling twelve-month average, was first confirmed in January 2011, and PSE continues to meet the requirement.

Further, Colstrip met the Mercury and Air Toxics Standard (MATS) limits for mercury and acid gases as of April 2017.

Siting New Facilities

In siting new generation, transmission, distribution or other related facilities in Washington, PSE is subject to the State Environmental Policy Act, and may be subject to the federal National Environmental Policy Act, if there is a federal nexus, in addition to other possible local siting and zoning ordinances. These requirements may potentially require mitigation of environmental impacts as well as other measures that can add significant cost to new facilities.

Recent and Future Environmental Law and Regulation

Recent and future environmental laws and regulations may be imposed at a federal, state or local level and may have a significant impact on the cost of PSE operations. PSE monitors legislative and regulatory developments for environmental issues with the potential to alter the operation and cost of our generation plants, transmission and distribution system, and other assets. Described below are the recent, pending and potential future environmental law and regulations with the most significant potential impacts to PSE’s operations and costs.

Climate Change and Greenhouse Gas Emissions

PSE ~~recognizes the growing concern that increased atmospheric concentrations of GHG contribute~~takes seriously environmental stewardship, implementing both short-term measures and long-term strategies designed to ~~climate change. PSE believes that climate change is an important issue that requires careful analysis~~manage greenhouse gas emissions in a scientifically sound and ~~considered responses. As climate policy continues to evolve at the~~responsible fashion. The Company has worked closely with federal, state and ~~federal levels,~~local governments on deep decarbonization, and the reduction and mitigation of greenhouse gases. As a result, the Company intends and expects be net zero methane emissions by 2022, coal free by 2025 and its electric system will be carbon neutral by 2030. The Company is also helping Washington State address greenhouse gas emissions from the transportation sector by investing in electric vehicles, as well as the development of liquefied natural gas for maritime and commercial transportation. PSE also remains ~~involved~~mindful of our customers' expectation of reliable, affordable service. The Company considers the cost of the decarbonization efforts to date, as well as future efforts in ~~state, regional~~its IRP process, and ~~federal policymaking activities. PSE~~ will continue to ~~monitor the development of any~~engage in climate ~~change or climate change related air emission reduction initiative at the state~~ and ~~western regional level. PSE will also consider the known impact of any future legislation or new government regulation on the cost of generation in its IRP process.~~greenhouse gas policy development.

PSE's Greenhouse Gas Emission Reporting

PSE is required to submit, on an annual basis, a report of its GHG emissions to the state of Washington Department of Ecology including a report of emissions from all individual power plants emitting over 10,000 tons per year of GHGs and from certain natural gas distribution operations. Emissions exceeding 25,000 tons per year of GHGs from these sources must also be reported to the environmental protection agency (EPA). Capital investments to monitor GHGs from the power plants and in the distribution system are not required at this time. Since 2002, PSE has voluntarily undertaken an annual inventory of its GHG emissions associated with PSE’s total electric retail load served from a supply portfolio of owned and purchased resources.

The most recent data indicate that PSE’s total GHG emissions (direct and indirect) from its electric supply portfolio in ~~2015~~2017 were ~~11.9~~10.2 million metric tons of carbon dioxide equivalents. Approximately ~~41.49%~~43.7% of PSE’s total GHG emissions (approximately ~~5.0~~4.5 million metric tons) are associated with PSE’s ownership and contractual interests in ~~Colstrip. While~~ Colstrip ~~remains a significant portion~~(with the closure of ~~PSE’s~~Units 1&2 effective December 31, 2019, PSE expects an approximately 45% reduction in Colstrip GHG ~~emissions, Colstrip is an important part of the existing diversified portfolio PSE owns and/or operates for its customers. Consequently,~~emissions). PSE’s overall emissions strategy demonstrates a concerted effort to manage customers’ needs with an appropriate balance of new renewable generation, existing generation owned and/or operated by PSE and significant energy efficiency efforts.

Federal Greenhouse Gas ~~Rules~~Rules: New and Existing Power Plants

On ~~August 3,~~October 23, 2015, the EPA ~~announced~~published a final rule regarding New Source Performance Standard (NSPS) for the control of carbon dioxide (CO₂) from new power plants that burn fossil fuels under section 111(b) of the Clean Air Act. ~~The rule was published on October 23, 2015, and separates standards for new power plants fueled by natural gas and coal.~~ New natural

gas power plants can emit no more than 1,000 lbs. of CO₂/megawatt hour (MWh) which is achievable with the latest combined cycle technology. New coal power plants can emit no more than 1,400 lbs. of CO₂/~~MWh, which is less stringent than the draft rule. The standard for coal plants would not specifically require~~MWh. Carbon Dioxide Capture and Sequestration (CCS) ~~but CCS~~ was reaffirmed by the EPA in this rule as the “best system of emission reductions” (BSER). ~~These 111(b)~~

On December 20, 2018, the EPA published a proposed rule that would revise the NSPS for greenhouse gas emissions from new, modified, and reconstructed fossil fuel-fired power plants. The Proposed Rule, would revise the emissions standards for new, modified, and reconstructed fossil fuel-fired electric utility steam generating units that are ~~implemented by~~either utility boilers or integrated gasification combined cycle (IGCC) units based on the ~~states, but states have limited flexibility to alter~~Agency’s proposed revised Best System of Emission Reduction (BSER). The EPA is not proposing any changes nor reopening the standards ~~set by~~of performance for newly constructed or reconstructed stationary combustion turbines.. For large units, the ~~EPA.~~

BSER is proposed to be super-critical steam conditions, and if revised, the emission rate will be 1,900 pounds of CO₂ per megawatt-hour on a gross output basis (lb. CO₂/MWh-gross). For small units, the BSER is proposed to be subcritical steam conditions, and if revised, the emission rate will be 2,000 lbs. of CO₂/MWh-gross. The EPA ~~announced~~proposes to replace the ~~final rule~~CCS BSER determination with a BSER for ~~111(d),~~newly constructed coal-fired units based on the most efficient demonstrated steam cycle in combination with the best operating practices. The primary reason for this proposed revision is the high costs and limited geographic availability of CCS.

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule ~~on August 3, 2015~~under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published ~~it on~~a final rule in October ~~23,~~ 2015. ~~The rule included several changes from~~In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the ~~draft rule. Specifically,~~proposed CPP federal plan and model trading rules and, in October 2017, the EPA ~~excluded energy efficiency~~proposed to repeal the CPP rule.

In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act.. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from ~~one of four "building blocks" identified in the draft rule, leaving just three building blocks (i) increased efficiency for coal plants, (ii) greater utilization of natural gas plants~~existing coal-fired plants. Compliance plans under ACE are due July 2020, and ~~(iii) increased renewable sources. In~~compliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations pending the EPA provided more flexibility in achieving interim goals by phasing in the reduction and giving states the option to set their own interim compliance glide path and pushing the start of compliance to 2022. The EPA also adjusted the 2012 baseline to address hydroelectricity variability and provided specific CO₂ ~~mass targets by year for each state.~~

States have broad flexibility to pick a rate-based or mass-based approach and can design compliance options and decide how to allocate credits and whether to allow trading. The EPA also gave states the option of seeking additional time, if necessary, to formulate a state plan. States must submit something within one year but can request up to an additional two years for development of a state plan. Thus, states must submit a plan for implementing CO₂ ~~reductions to the EPA one to three years following issuance~~outcome of the ~~final rule.~~proposed Colstrip sale to NorthWestern Energy.

Washington Clean Air Rule

The ~~Clean Air Rule (CAR)~~CAR was adopted onin September ~~15,~~ 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5%5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others.

OnIn September ~~27,~~ 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed ~~an action~~a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. OnIn September ~~30,~~ 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. ~~While awaiting~~In March 2018, the ~~outcome~~Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. Meanwhile, the federal court litigation has been held in abeyance pending ~~litigation,~~resolution of the ~~Company has undertaken steps~~state case.

Washington Clean Energy Transition Act

In May 2019, Washington State passed the 100 Percent Clean Electric Bill that supports Washington's clean energy economy and transitioning to ~~comply with the first compliance period~~a clean, affordable, and reliable energy future. The Clean Energy Transition Act requires all electric utilities to eliminate coal-fired generation from their allocation of ~~CAR, which began~~electricity by December 31, 2025; to be carbon-neutral by January 1, ~~2017.~~

~~Mercury Emissions~~

~~Mercury control equipment has been installed at Colstrip~~2030, through a combination of non-emitting electric generation, renewable generation, and/or alternative compliance options; and ~~has operated at a level~~makes it the state policy that, ~~meets~~by 2045, 100% of electric generation and retail electricity sales will come from renewable or non-emitting resources. Clean Energy Implementation plans are required every four years from each investor-owned utility (IOU) and must propose interim targets for meeting the ~~current Montana requirement. Compliance, based on a rolling 12-month average, was first confirmed in January 2011,~~2045 standard between 2030 and ~~PSE continues~~2045, and lay out an actionable plan that they intend to pursue to meet the ~~requirement.~~standard. The Washington Commission may approve, reject, or recommend alterations to an IOU’s plan.

In order to meet these requirements, the Act clarifies the Washington Commission’s authority to consider and implement performance and incentive- based regulation, multi-year rate plans, and other flexible regulatory mechanisms where appropriate. The Act mandates that the Washington Commission accelerate depreciation schedules for coal-fired resources, including transmission lines, to December 31, 2025, or to allow IOUs to recover costs in rates for earlier closure of those

facilities. IOUs will be allowed to earn a rate of return on certain Power Purchase Agreements (PPA's) and 36 months deferred accounting treatment for clean energy projects (including PPAs) identified in the utility’s clean energy implementation plan.

IOUs are considered to be in compliance when the cost of meeting the standard or an interim target within the four-year period between plans equals a 2% increase in the weather adjusted sales revenue to customers from the previous year. If relying on the cost cap exemption, IOUs must demonstrate that they have maximized investments in renewable resources and non-emitting generation prior to using alternative compliance measures.

The ~~EPA published~~law requires additional rulemaking by several Washington agencies for its measures to be enacted and PSE is unable to predict outcomes at this time. The Company intends to seek recovery of any costs associated with the final Mercury and Air Toxics Standard (MATS) in February 2012. Generating units were given three years, until April 2015, to comply with MATS and could receive up to a 1-year extension from state permitting authorities if necessary forclean energy legislation through the ~~installation of controls. Colstrip met the MATS limits for mercury and acid gases as of April 2016.~~regulatory process.

Regional Haze Rule

~~On June 15, 2005,~~In January 2017, the EPA ~~issued the Clean Air Visibility rule~~provided revisions to address regional haze or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units, including presumptive limits for sulfur dioxide, particulate matter and nitrogen oxide controls for large units. The final Federal Implementation Plan for Montana (FIP) for Regional Haze was issued in September 2012. There are no immediate requirements for Units 3 and 4, but Units 1 and 2 will need to upgrade pollution controls to meet new sulfur dioxide and nitrogen oxide limits. The Sierra Club filed an appeal of the FIP with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) on November 15, 2012 and PPL Montana also filed an appeal as the Colstrip operator.

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

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

~~In July 2016, the EPA proposed to delay~~Federal Register. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, ~~and that proposal is currently awaiting approval,~~ however, the end date will remain 2028. In January 2018, the ~~meantime, Montana has indicated~~EPA announced that ~~they plan~~it would revisit certain aspects of these revisions and PSE is unable to ~~work on and submit a State Implementation Plan~~predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the ~~second planning period.~~D.C. Circuit, pending resolution of EPA’s reconsideration of the rule.

Coal Combustion Residuals

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

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

The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA.As a result of that decision and certain other developments, EPA has is working on developing new rules regarding CCR, including a new proposed date of August 31, 2020, for facilities to stop placing coal ash into unlined surface impoundments.In addition, the EPA has stated that it will soon propose a federal permitting program for coal ash disposal units.

PCB Handling and Disposal

In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking ~~(ANPRM)~~ soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA is using this ~~ANPRM~~Advanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs.

The rule was scheduled to be published in July 2015, but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. ~~According to~~It was anticipated that the ~~EPA, the notice of proposed rulemaking is projected to~~rule would be published in November 2017. However, in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group ~~(USWAG)~~ and the American Gas Association (AGA) to monitor developments.

Executive Officers of the Registrants

The executive officers of Puget Energy as of ~~March 2, 2017~~February 21, 2020, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.



Name	~~Age~~	Age	Offices
~~K. J. Harris~~M. E. Kipp	52	52	President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer ~~since March 2011~~at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014.
D. A. Doyle	58	61	Senior Vice President and Chief Financial Officer since November 2011
S. R. Secrist	55	58	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. R. Marcelia~~S. J. King	48	36	Controller and Principal Accounting Officer since ~~May 2016; Director of Tax January 2005~~November 2, 2017. Senior Manager at PricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - ~~May~~November 2017; Manager at PwC July 2013 - July 2016

The executive officers of PSE as of ~~March 2, 2017~~February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.



Name		~~Age~~			Age		Offices
~~K. J. Harris~~M. E. Kipp		52			52		President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer ~~since March 2011~~at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014.
D. A. Doyle		58			61		Senior Vice President and Chief Financial Officer since November 2011
~~P. K. Bussey~~		60		~~Senior Vice President and Chief Customer Officer since March 2012. Prior to PSE, he was President and Chief Executive Officer of Seattle Metropolitan Chamber May 2009 – March 2012~~
B. K. Gilbertson	53		56			Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February ~~2015; Vice President, Operations Services February 2011 – February 2013~~2015
M. D. Mellies		56			59		Senior Vice President and Chief Administrative Officer since February 2011
D. E. Mills					62		Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015
S. R. Secrist		55			58		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. R. Marcelia~~S. J. King		48			36		Controller and Principal Accounting Officer since ~~May 2016; Director of Tax January 2005~~November 2, 2017. Senior Manager at PwC July 2016 - ~~May~~November 2017; Manager at PwC July 2013 - July 2016

ITEM 1A. RISK FACTORS

The following risk factors, in addition to other factors and matters discussed elsewhere in this report, should be carefully considered. The risks and uncertainties described below are not the only risks and uncertainties that Puget Energy and PSE may face. Additional risks and uncertainties not presently known or currently deemed immaterial also may impair PSE’s business operations. If any of the following risks actually occur, Puget Energy’s and PSE’s business, results of operations and financial conditions would suffer.

RISKS RELATING TO PSE’s REGULATORY AND RATE-MAKING PROCEDURES

PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.

The actions of regulators can significantly affect PSE’s earnings, liquidity and business activities. The rates that PSE is allowed to charge for its services isare the single most important item influencing its financial position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its wholesale and retail customers are determined by both the Washington Commission and the FERC.

PSE is also subject to the regulatory authority of the Washington Commission with respect to accounting, operations, the issuance of securities and certain other matters, and the regulatory authority of the FERC with respect to the transmission of electric energy, the sale of electric energy at the wholesale level, accounting and certain other matters. In addition, proceedings with the Washington Commission typically involve multiple stakeholder parties, including consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or decreasing rates. Policies and regulatory actions by these regulators could have a material impact on PSE’s financial position, results of operations and liquidity.

PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed. The Washington Commission determines the rates PSE may charge to its electric retail customers based, in part, on historic costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing ~~12-month~~twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine what level of expense and investment is reasonable and prudent in providing electric and natural gas service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For the aforementioned reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.

PSE is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with ~~an ERF,~~ a rate plan and an earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of ~~7.77% during the term of the rate plan.~~7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the ~~threshold,~~authorized rate of return, even if the other service did not ~~meet~~exceed the ~~earnings test. The decoupling mechanism will end on December 31, 2017 unless the continuation~~authorized rate of ~~the mechanism is approved in PSE's GRC which was filed on January 13, 2017.~~return.

The PCA mechanism, by which variations in PSE’s power costs are apportioned between PSE and its customers pursuant to a graduated scale, could result in significant increases in PSE’s expenses if power costs are significantly higher than the baseline rate. PSE has a PCA mechanism that provides for recovery of power costs from customers or refunding of power cost savings to customers, as those costs vary from the “power cost baseline” level of power costs which are set, in part, based on normalized assumptions about weather and hydrological conditions. Excess power costs or power cost savings will be apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached. As a result, if power costs are significantly higher than the baseline rate, PSE’s expenses could significantly increase.

RISKS RELATING TO PSE’s OPERATION

PSE’s cash flow and earnings could be adversely affected by potential high prices and volatile markets for purchased power, recurrence of low availability of hydroelectric resources, outages of its generating facilities or a failure to deliver on the part of its suppliers. The utility business involves many operating risks. If PSE’s operating expenses, including the cost of purchased power and natural gas, significantly exceed the levels recovered from retail customers, its cash flow and earnings would be negatively affected. Factors which could cause PSE's purchased power and natural gas costs to be higher than anticipated include, but are not limited to, high prices in western wholesale markets during periods when PSE has insufficient energy resources to meet its energy supply needs and/or purchases in wholesale markets of high volumes of energy at prices above the amount recovered in retail rates due to:

•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

•Extended outages of any of PSE-owned generating facilities or the transmission lines that deliver energy to load centers, or the effects of large-scale natural disasters on a substantial portion of distribution infrastructure; and

•Failure of a counterparty to deliver capacity or energy purchased by PSE.

PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. PSE owns and operates coal, natural gas-fired, hydroelectric, ~~wind-powered~~ and ~~oil-fired~~wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:

•Facility shutdowns due to a breakdown or failure of equipment or processes;

•Volatility in prices for fuel and fuel transportation;

•Disruptions in the delivery of fuel and lack of adequate inventories;

•Regulatory compliance obligations and related costs, including any required environmental remediation, and any new laws and regulations that necessitate significant investments in our generating facilities;

•Labor disputes;

•Operator error or safety related stoppages;

•Terrorist or other attacks (both cyber-based and/or asset-based); and

•Catastrophic events such as fires, explosions or acts of nature.

~~If PSE is unable~~Cyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to ~~protect its physical assets from terrorist attacks or its~~the disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and ~~network against~~cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company data ~~corruption, cyber-based attacks~~that is crucial to PSE's operational security or ~~network~~could adversely affect PSE's ability to deliver and collect on customer bills. Such security breaches ~~its~~of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to financial liability or increased regulation, expose PSE to fines or material legal claims and liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could ~~be disrupted.~~ ~~Despite~~adversely affect PSE’s financial condition and results of operations.

Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's ~~implementation of security measures, its physical~~business. Events such as fires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and ~~technology systems~~pipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If the technology systems were to fail or be breached and PSE were unable to recover in a timely manner, PSE may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have ~~a material~~an adverse ~~effect~~impact on ~~its results of~~PSE's operations, financial condition, and ~~cash flows. In addition, these physical asset or cyber-based attacks could disrupt its ability to produce or distribute some portion~~results of ~~our energy products~~operations. The availability of insurance covering catastrophic events, sabotage and could affect the reliability or operability of the electric and natural gas systems. As a result, PSE endeavors to maintain vigilant security programs and procedures to protect against the continuous threat of physical asset and cyber-based attacks, and as a result, PSEterrorism may be ~~required to expend significant dollars~~limited or may result in higher deductibles, higher premiums, and ~~other resources to protect against existing and ensuing threats.~~more restrictive policy terms.

PSE is subject to the commodity price, delivery and credit risks associated with the energy markets. In connection with matching PSE's energy needs and available resources, PSE engages in wholesale sales and purchases of electric capacity and energy and, accordingly, is subject to commodity price risk, delivery risk, credit risk and other risks associated with these activities. Credit risk includes the risk that counterparties owing PSE money or energy will breach their obligations for delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. Should the counterparties to these arrangements fail to perform, PSE may be forced to enter into alternative arrangements. In that event, PSE’s financial results could be adversely affected. Although PSE takes into account the expected probability of default by counterparties, the actual exposure to a default by a particular counterparty could be greater than predicted.

Costs of compliance with environmental, climate change and endangered species laws are significant and the costs of compliance with new and emerging laws and regulations and the ~~incurrence~~occurrence of associated liabilities could adversely

affect PSE’s results of operations. PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE must spend significant sums of money to comply with these measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and emissions related abatement and fees. New environmental laws and regulations affecting PSE’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities. Compliance with these or other future regulations could require significant expenditures by PSE and adversely affect ~~PSE’s financial position, results of operations, cash flows and liquidity.~~PSE financially. In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates, in a timely manner, at current levels in the future.

Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated. The ~~incurrence~~occurrence of a material environmental liability or new regulations governing such liability could result in substantial future costs and have a material adverse effect on PSE’s results of operations and financial condition.

Specific to climate change, Washington State has adopted both renewable portfolio standards and GHG legislation, including ~~an emission performance standard provision~~CETA, and PSE anticipates full compliance with these requirements.

PSE's inability to adequately develop or acquire the necessary infrastructure to comply with new and emerging laws and regulations could have a material adverse impact on our business and results of operations. Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the ~~EPA set CO~~₂ ~~emission standards~~need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with ~~specific state goals.~~ environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to renewables development and energy efficiency measures, create strategic challenges as to the appropriate generation portfolio and fuel diversification mix.

In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Municipal, State and Federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.

PSE's operating results fluctuate on a seasonal and quarterly basis and can be impacted by various impacts of climate change. PSE's business is seasonal and weather patterns can have a material impact on its revenue, expenses and operating results. Demand for electricity is greater in the winter months associated with heating. Accordingly, PSE's operations have historically generated less revenue and income when weather conditions are milder in winter. In the event that the Company experiences unusually mild winters, its results of operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.

PSE may be adversely affected by extreme events in which PSE is not able to promptly respond, repair and restart the electric and natural gas infrastructure system. PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events. Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers and also require significant expenditures by PSE. In addition, a slow or ineffective response to extreme events may have an adverse effect on earnings as customers may be without electricity and natural gas for an extended period of time.

PSE depends on ~~an aging~~its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to ~~an aging workforce,~~ loss or retirement of key personnel and availability of qualified personnel. PSE’s ability to implement a workforce succession plan is dependent upon PSE’s ability to employ and retain skilled professional and technical workers. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and to meet regulatory requirements could affect PSE’s earnings. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.

PSE continues to be concerned about the availability ~~and aging~~ of skilled workers for special complex utility functions. PSE also hires third party vendors to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and natural gas distribution construction and maintenance, certain billing and

metering processes, call center overflow and credit and collections. The unavailability of skilled workers or unavailability of such vendors could adversely affect the quality and cost of PSE’s natural gas and electric service and accordingly PSE’s results of operations.

Potential municipalization may adversely affect PSE's financial condition. PSE may be adversely affected if we experience a loss in the number of our customers due to municipalization or other related government action. When a town or city in PSE's service territory establishes its own municipal-owned utility, it acquires PSE's assets and takes over the delivery of energy services that PSE provides. Although PSE is compensated in connection with the town or city's acquisition of its assets, any such loss of customers and related revenue could negatively affect PSE's future financial condition.

Coal Combustion Residuals

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

PCB Handling and Disposal

In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking soliciting information on a broad range of questions concerning inventory, management, use, and disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA is using this Advanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a rulemaking process geared toward a mandatory phase-out of all PCBs.

The rule was scheduled to be published in July 2015, but due to the number of comments received by the EPA, the rule has undergone multiple extensions and revisions. It was anticipated that the rule would be published in November 2017. However, in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot determine what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the Utility Solid Waste Activities Group and the American Gas Association (AGA) to monitor developments.

Executive Officers of the Registrants

The executive officers of Puget Energy as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of Puget Energy are elected for one-year terms.

Name

Age

Offices

M. E. Kipp

President since August 2019; Chief Executive Officer since January 2020. President and Chief Executive Officer at El Paso Electric from May 2017 to August 2019; Chief Executive Officer at El Paso Electric from December 2015 to May 2017; President at El Paso Electric from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer at El Paso Electric from June 2010 to September 2014.

D. A. Doyle

Senior Vice President and Chief Financial Officer since November 2011

S. R. Secrist

Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014

S. J. King

Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PricewaterhouseCoopers LLP (PwC), a public accounting firm, July 2016 - November 2017; Manager at PwC July 2013 - July 2016

The executive officers of PSE as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.

Name

Age

Offices

M. E. Kipp

D. A. Doyle

Senior Vice President and Chief Financial Officer since November 2011

B. K. Gilbertson

Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015

M. D. Mellies

Senior Vice President and Chief Administrative Officer since February 2011

D. E. Mills

Senior Vice President, Policy and Energy Supply since February 2018; Senior Vice President, Energy Operations January 2017 - February 2018; Vice President, Energy Operations January 2016 - January 2017; Vice President, Energy Supply Operations January 2012 - January 2015

S. R. Secrist

Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014

S. J. King

Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016

ITEM 1A. RISK FACTORS

RISKS RELATING TO ~~PUGET ENERGY'S~~PSE’s REGULATORY AND ~~PSE'S FINANCING~~RATE-MAKING PROCEDURES

~~The Company's~~PSE's regulated utility business is ~~dependent~~subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.

The actions of regulators can significantly affect PSE’s earnings, liquidity and business activities. The rates that PSE is allowed to charge for its services are the single most important item influencing its financial position, results of operations and liquidity. PSE is highly regulated and the rates that it charges its wholesale and retail customers are determined by both the Washington Commission and the FERC.

PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed. The Washington Commission determines the rates PSE may charge to its electric retail customers based, in part, on historic costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine what level of expense and investment is reasonable and prudent in providing electric and natural gas service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For the aforementioned reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.

PSE is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan and earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the authorized rate of return, even if the other service did not exceed the authorized rate of return.

RISKS RELATING TO PSE’s OPERATION

•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

•Failure of a counterparty to deliver capacity or energy purchased by PSE.

PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. PSE owns and operates coal, natural gas-fired, hydroelectric, and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:

•Facility shutdowns due to a breakdown or failure of equipment or processes;

•Volatility in prices for fuel and fuel transportation;

•Disruptions in the delivery of fuel and lack of adequate inventories;

•Labor disputes;

•Operator error or safety related stoppages;

•Terrorist or other attacks (both cyber-based and/or asset-based); and

•Catastrophic events such as fires, explosions or acts of nature.

Cyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to the disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to ~~successfully access capital.~~ ~~The~~safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company ~~relies~~data that is crucial to PSE's operational security or could adversely affect PSE's ability to deliver and collect on ~~access~~customer bills. Such security breaches of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to ~~internally generated funds, bank borrowings through multi-year committed credit facilities~~financial liability or increased regulation, expose PSE to fines or material legal claims and ~~short-term money markets~~liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could adversely affect PSE’s financial condition and results of operations.

Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's business. Events such as ~~sources of liquidity and longer-term debt markets to fund PSE's utility construction program~~fires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other ~~capital expenditure requirements~~similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of ~~PSE. If Puget Energy~~PSE's suppliers or ~~PSE are unable to access capital on reasonable terms, their~~customers. These events could disrupt PSE's ability to ~~pursue improvements~~meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or ~~acquisitions, including generating capacity, which~~a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations. The availability of insurance covering catastrophic events, sabotage and terrorism may be ~~necessary~~limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.

PSE is subject to the commodity price, delivery and credit risks associated with the energy markets. In connection with matching PSE's energy needs and available resources, PSE engages in wholesale sales and purchases of electric capacity and energy and, accordingly, is subject to commodity price risk, delivery risk, credit risk and other risks associated with these activities. Credit risk includes the risk that counterparties owing PSE money or energy will breach their obligations for ~~future growth,~~delivery of energy supply or contractually required payments related to PSE's energy supply portfolio. Should the counterparties to these arrangements fail to perform, PSE may be forced to enter into alternative arrangements. In that event, PSE’s financial results could be adversely affected. ~~Capital~~Although PSE takes into account the expected probability of default by counterparties, the actual exposure to a default by a particular counterparty could be greater than predicted.

Costs of compliance with environmental, climate change and ~~credit market disruptions, a downgrade~~endangered species laws are significant and the costs of ~~Puget Energy's or PSE's credit rating or~~compliance with new and emerging laws and regulations and the ~~imposition~~occurrence of restrictions on borrowings under their credit facilities in the event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

~~The amount of the Company's debt~~associated liabilities could adversely

affect ~~its liquidity and~~PSE’s results of operations. ~~Puget Energy~~PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE ~~have short-term~~must spend significant sums of money to comply with these measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and ~~long-term debt,~~emissions related abatement and fees. New environmental laws and regulations affecting PSE’s operations may ~~incur additional debt (including secured debt) in the future. Puget Energy has access~~be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to ~~a multi-year $800.0 million revolving credit facility, secured~~PSE or its facilities. Compliance with these or other future regulations could require significant expenditures by ~~substantially~~PSE and adversely affect PSE financially. In addition, PSE may not be able to recover all of its ~~assets, which has~~costs for such expenditures through electric and natural gas rates, in a ~~maturity date of April 15, 2018. There was $12.5 million outstanding under~~timely manner, at current levels in the ~~facility as of December 31, 2016. Puget Energy's credit facility includes an accordion feature that could, upon~~future.

Under current law, PSE is also generally responsible for any on-site liabilities associated with the banks' approval, increase the size of the facility to $1.3 billion. PSE also has two credit facilities, which provide PSE with access to $1.0 billion in short-term borrowing capability, and include an accordion feature that could, upon the banks' approval, increase the sizeenvironmental condition of the facilities ~~to $1.5 billion.~~that it currently owns or operates or has previously owned or operated. The ~~two PSE credit facilities mature~~occurrence of a material environmental liability or new regulations governing such liability could result in substantial future costs and have a material adverse effect on ~~April 15, 2019. As~~PSE’s results of December 31, 2016, no amounts were drawn and outstanding under the PSE credit facilities. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2016, had approximately $3.8 billion outstanding under first mortgage bonds, pollution control bonds, senior notes and junior subordinated notes. The Company's debt level could have important effects on the business, including but not limited to:

~~Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;~~

~~Making it difficult to fund non-debt service related~~ operations ~~of the business; and~~

~~Limiting the Company's financial flexibility, including its ability to borrow additional funds on favorable terms or at all.~~

~~A downgrade in Puget Energy’s or PSE’s credit rating could negatively affect the ability to access capital, the ability to hedge in wholesale markets and the ability to pay dividends.~~ Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect the ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy’s and PSE’s facilities, the borrowing spreads over the London Interbank Offered Rate (LIBOR) and commitment fees increase if their respective corporate credit ratings decline. A downgrade in commercial paper ratings could increase the cost of commercial paper and limit or preclude PSE’s ability to issue commercial paper under its current programs.

~~Any downgrade below investment grade of PSE’s corporate credit rating could cause counterparties in the wholesale electric, wholesale natural gas~~ and financial ~~derivative markets~~condition. Specific to ~~request~~climate change, Washington State has adopted both renewable portfolio standards and GHG legislation, including CETA, and PSE anticipates full compliance with these requirements.

PSE's inability to ~~post a letter of credit~~adequately develop or ~~other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSE~~acquire the necessary infrastructure to ~~additional costs.~~

PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciationcomply with new and ~~amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.~~

~~The Company may be negatively affected by unfavorable changes in the tax~~emerging laws ~~or their interpretation.~~ ~~The Company’s tax obligations include income, real estate, public utility, municipal, sales~~ and ~~use, business and occupation and employment-related taxes and ongoing audits related to these taxes. Changes in tax law, related~~ regulations ~~or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction~~ could have a material adverse impact on ~~the Company’s financial statements. The tax law, related regulations~~our business and ~~case law are inherently complex. The Company must make judgments and interpretations about the application~~results of ~~the law when determining the provision for taxes. These judgments may include~~

reserves for potential adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.

~~In connection with the change in administration in Washington, D.C., there may be a higher likelihood of substantive~~operations. Potential changes in ~~federal law or regulation, including changes to~~regulatory standards, impacts of new and existing laws and regulations, ~~governing corporate tax,~~including environmental ~~protection, healthcare,~~laws and regulations, and the need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with environmental, regulatory, and other ~~areas, any of which could affect PSE's operations or financial results. However, at this time PSE is unable~~concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to ~~speculate~~renewables development and energy efficiency measures, create strategic challenges as to the ~~likely impact~~appropriate generation portfolio and fuel diversification mix.

In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting and construction of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Municipal, State and Federal environmental regulation and the increasing financial resources devoted to these opposition activities. PSE cannot predict the effect that any such ~~changes.~~ opposition may have on our ability to develop and construct fossil fuel infrastructure projects in the future.

~~Poor performance of pension~~PSE's operating results fluctuate on a seasonal and ~~postretirement benefit plan investments and other factors impacting plan costs could unfavorably impact PSE’s cash flow and liquidity.~~ PSE provides a defined benefit pension plan to PSE employees and postretirement benefits to certain PSE employees and former employees. Costs of providing these benefits are based, in part, on the value of the plan’s assets and the current interest rate environment and therefore, adverse market performance or low interest rates could result in lower rates of return for the investments that fund PSE’s pension and postretirement benefits plans and could increase PSE’s funding requirements related to the pension plans. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in 2017 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.

~~Potential legal proceedings and claims could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business.~~ The Company is, from time to time, subject to various legal proceedings and claims, either asserted or unasserted. Any such claims, whether with or without merit, could be time-consuming and expensive to defend and could divert management’s attention and resources. While management believes the Company has reasonable and prudent insurance coverage and accrues loss contingencies for all known matters that are probablequarterly basis and can be ~~reasonably estimated, the Company cannot assure that the outcome~~impacted by various impacts of ~~all current or future litigation will not~~climate change. PSE's business is seasonal and weather patterns can have a material ~~adverse effect~~impact on its revenue, expenses and operating results. Demand for electricity is greater in the winter months associated with heating. Accordingly, PSE's operations have historically generated less revenue and income when weather conditions are milder in winter. In the event that the Company ~~and/or~~experiences unusually mild winters, its results of ~~operations.~~operations and financial condition could be adversely affected. PSE's hydroelectric resources are also dependent on snow conditions in the Pacific Northwest.

~~RISKS RELATING TO PUGET ENERGY'S CORPORATE STRUCTURE~~

~~Puget Energy's ability to pay dividends~~PSE may be ~~limited.~~ As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholder, is cash dividends PSE pays to Puget Energy.adversely affected by extreme events in which PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends or repay debt or other expenses, will depend on PSE’s earnings, capital requirements and general financial condition. If Puget Energy does not ~~receive adequate distributions from PSE, it may not be~~ able to ~~meet its obligations or pay dividends.~~

~~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~~promptly respond, repair and restart the electric and natural gas ~~mortgage indentures.~~infrastructure system. PSE must maintain an emergency planning and training program to allow PSE to quickly respond to extreme events. Without emergency planning, PSE is subject to availability of outside contractors during an extreme event which may impact the quality of service provided to PSE’s customers and also require significant expenditures by PSE. In addition, ~~beginning February 6, 2009, pursuant~~a slow or ineffective response to extreme events may have an adverse effect on earnings as customers may be without electricity and natural gas for an extended period of time.

PSE depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the ~~terms~~unavailability of ~~the Washington Commission merger order,~~ vendors. PSE ~~may~~is subject to workforce factors, including but not ~~declare~~limited to loss 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's ability to declare or make any distribution is limited by its' corporate credit/issuer ratingretirement of key personnel and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 and the EBITDA to interest expense was 5.2 to 1.0 for the 12 months ended.

availability of qualified personnel. PSE’s ability to ~~pay dividends~~implement a workforce succession plan is dependent upon PSE’s ability to employ and retain skilled professional and technical workers. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and to meet regulatory requirements could affect PSE’s earnings. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.

PSE continues to be concerned about the availability of skilled workers for special complex utility functions. PSE also ~~limited by the terms~~hires third party vendors to perform a variety 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,normal business functions, such as ~~failure to comply with~~power plant maintenance, data warehousing and management, electric transmission, electric and natural gas distribution construction and maintenance, certain ~~financial covenants.~~billing and

~~Challenges relating to the construction~~metering processes, call center overflow and credit and collections. The unavailability of skilled workers or ~~future operation~~unavailability of ~~the Tacoma LNG facility~~such vendors could adversely affect the ~~Company’s operations.~~ ~~PSE~~quality and ~~Puget Energy’s subsidiary, Puget LNG, currently are constructing the Tacoma LNG facility at the Port~~cost of ~~Tacoma, a jointly owned facility intended to provide peak-shaving services to~~ PSE’s natural gas and electric service and accordingly PSE’s results of operations.

Technological developments may have an adverse impact on PSE's financial condition. Advances in power generation, energy efficiency and other alternative energy technologies, such as solar generation, could lead to ~~provide LNG as fuel primarily to~~more wide-spread use of these technologies, thereby reducing customer demand for the maritime market. Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers. Scheduled to be completed in 2019, delays in the facility’s construction and operation or in its ability to timely deliver fuel to customers could expose Puget LNG to damages under one or more fuel supply contracts,energy supplied by PSE which could ~~unfavorably~~negatively impact ~~Puget Energy’s return on investment.~~PSE's revenue and financial condition.

~~ITEM 1B. UNRESOLVED STAFF COMMENTS~~

~~None.~~

~~ITEM 2. PROPERTIES~~

The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, Business – Electric Supply and Natural Gas Supply. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. The Company’s corporate headquarters is housed in a leased building located in Bellevue, Washington.

~~ITEM 3. LEGAL PROCEEDINGS~~

From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations:

~~Colstrip~~

PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE has reclassified $176.8 million from a plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the asset retirement obligation (ARO) for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs are unknown and will vary from the estimates that are available at this time.

~~Greenwood~~

On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint September 20, 2016, seeking from PSE $3.2 million in fines. As a result, the Washington Commission will initiate a hearing before making a final determination. As of December 31, 2016, PSE has accrued $3.2 million for the fine.

Coal Combustion Residuals

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

in lieu of the current self-implementing rule, as long as Congress grants the funding for the EPA to do so. This would not eliminate the threat of citizen lawsuits, but could provide more certainty regarding interpretations and ultimate compliance. If no permit program is in effect in a state, the CCR rule will remain self-implementing.

The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the ~~ARO.~~Asset Retirement and Environmental Obligations (ARO). In 2018, the D.C. Circuit Court of Appeals overturned certain provisions of the CCR rule in 2018 and remanded some of its provisions back to the EPA.As a result of that decision and certain other developments, EPA has is working on developing new rules regarding CCR, including a new proposed date of August 31, 2020, for facilities to stop placing coal ash into unlined surface impoundments.In addition, the EPA has stated that it will soon propose a federal permitting program for coal ash disposal units.

~~Clean Air Act 111(d)/EPA Clean Power Plan~~PCB Handling and Disposal

In ~~June 2014,~~April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking soliciting information on a ~~proposed Clean Power Plan rule under Section 111(d)~~broad range of ~~the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals~~questions concerning inventory, management, use, and ~~guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014.~~disposal of polychlorinated biphenyl (PCB) containing equipment. The EPA ~~published~~is using this Advanced Notice of Proposed Rulemaking to seek data to better evaluate whether to initiate a ~~final rule on October 23, 2015.~~ rulemaking process geared toward a mandatory phase-out of all PCBs.

The rule is being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. PSE began review of the final rule and is working with key stakeholderswas scheduled to be published in ~~preparation for implementation;~~July 2015, but due to the ~~stay, many states, including Montana have put off all discussion~~number of ~~implementation.~~comments received by the EPA, the rule has undergone multiple extensions and revisions. It was anticipated that the rule would be published in November 2017. However, ~~Washington has moved forward with its own Clean Air Rule.~~in January 2017, the Trump Administration published the Executive Order on Reducing Regulation and Controlling Regulatory Costs directive which placed the rulemaking on indefinite hold. At this point, PSE cannot ~~yet~~ determine ~~how~~what impacts this rulemaking will have on its operations, if any, but will continue to work closely with the ~~final rule~~Utility Solid Waste Activities Group and the American Gas Association (AGA) to monitor developments.

Executive Officers of the Registrants

Name

Age

Offices

M. E. Kipp

D. A. Doyle

Senior Vice President and Chief Financial Officer since November 2011

S. R. Secrist

Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014

S. J. King

The executive officers of PSE as of February 21, 2020, are listed below along with their business experience during the past five years. Officers of PSE are elected for one-year terms.

Name

Age

Offices

M. E. Kipp

D. A. Doyle

Senior Vice President and Chief Financial Officer since November 2011

B. K. Gilbertson

Senior Vice President, Operations since March 2015; Vice President, Operations March 2013 – February 2015

M. D. Mellies

Senior Vice President and Chief Administrative Officer since February 2011

D. E. Mills

S. R. Secrist

Senior Vice President, General Counsel and Chief Ethics and Compliance Officer since January 2014

S. J. King

Controller and Principal Accounting Officer since November 2, 2017. Senior Manager at PwC July 2016 - November 2017; Manager at PwC July 2013 - July 2016

ITEM 1A. RISK FACTORS

RISKS RELATING TO PSE’s REGULATORY AND RATE-MAKING PROCEDURES

PSE's regulated utility business is subject to various federal and state regulations. PSE's regulatory risks include, but are not limited to, the items discussed below.

PSE’s recovery of costs is subject to regulatory review and its operating income may be adversely affected if its costs are disallowed. The Washington Commission determines the rates PSE may charge to its electric retail customers based, in part, on historic costs during a particular test year, adjusted for certain normalizing adjustments. Power costs on the other hand, are normalized for market, weather and hydrological conditions projected to occur during the applicable rate year, the ensuing twelve-month period after rates become effective. The Washington Commission determines the rates PSE may charge to its natural gas customers based on historic costs during a particular test year. Natural gas costs are adjusted through the PGA mechanism, as discussed previously. If in a specific year PSE’s costs are higher than the amounts used by the Washington Commission to determine the rates, revenue may not be sufficient to permit PSE to earn its allowed return or to cover its costs. In addition, the Washington Commission has the authority to determine what level of expense and investment is reasonable and prudent in providing electric and natural gas service. If the Washington Commission decides that part of PSE’s costs do not meet the standard, those costs may be disallowed partially or entirely and not recovered in rates. For the aforementioned reasons, the rates authorized by the Washington Commission may not be sufficient to earn the allowed return or recover the costs incurred by PSE in a given period.

PSE is currently subject to a Washington Commission order that requires PSE to share its excess earnings above the authorized rate of return with customers. The Washington Commission previously approved an electric and natural gas decoupling mechanism for the recovery of its delivery-system and fixed production costs, along with a rate plan and earnings sharing mechanism that requires PSE and its customers to share in any earnings in excess of the authorized rate of return of 7.60%. The earnings test is done for each service (electric/natural gas) separately, so PSE would be obligated to share the earnings for one service exceeding the authorized rate of return, even if the other service did not exceed the authorized rate of return.

RISKS RELATING TO PSE’s OPERATION

•Below normal levels of generation by PSE-owned hydroelectric resources due to low streamflow conditions or precipitation;

•Failure of a counterparty to deliver capacity or energy purchased by PSE.

PSE’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. PSE owns and operates coal, natural gas-fired, hydroelectric, and wind-powered generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels or increase expenditures, including:

•Facility shutdowns due to a breakdown or failure of equipment or processes;

•Volatility in prices for fuel and fuel transportation;

•Disruptions in the delivery of fuel and lack of adequate inventories;

•Labor disputes;

•Operator error or safety related stoppages;

•Terrorist or other attacks (both cyber-based and/or asset-based); and

•Catastrophic events such as fires, explosions or acts of nature.

Cyber-attacks, including cyber-terrorism or other information technology security breaches, or information technology failures may disrupt business operations, increase costs, lead to the disclosure of confidential information and damage PSE's reputation. Security breaches of PSE's information technology infrastructure, including cyber-attacks and cyber-terrorism, or other failures of PSE's information technology infrastructure could lead to disruptions of PSE's production and distribution operations, and otherwise adversely impact PSE's ability to safely and effectively operate electric and natural gas systems and serve customers. In addition, an attack on or failure of information technology systems could result in the unauthorized release of customer, employee or Company data that is crucial to PSE's operational security or could adversely affect PSE's ability to deliver and collect on customer bills. Such security breaches of PSE's information technology infrastructure could adversely affect our operations and business reputation, diminish customer confidence, subject PSE to financial liability or increased regulation, expose PSE to fines or material legal claims and liability and adversely affect our financial results. PSE has implemented preventive, detective and remediation measures to manage these risks, and maintains cyber risk insurance to mitigate the effects of these events. Nevertheless, these may not effectively protect all of PSE's systems all of the time. To the extent that the occurrence of any of these cyber-events is not fully covered by insurance, it could adversely affect PSE’s financial condition and results of operations.

Natural disasters and catastrophic events, including terrorist acts, may adversely affect PSE's business. Events such as fires, earthquakes, explosions, floods, tornadoes, terrorist acts, and other similar occurrences, could damage PSE's operational assets, including utility facilities, information technology infrastructure, distributed generation assets and pipeline assets. Such events could likewise damage the operational assets of PSE's suppliers or customers. These events could disrupt PSE's ability to meet customer requirements, significantly increase PSE's response costs, and significantly decrease PSE's revenues. Unanticipated events or a combination of events, failure in resources needed to respond to events, or a slow or inadequate response to events may have an adverse impact on PSE's operations, financial condition, and results of operations. The availability of insurance covering catastrophic events, sabotage and terrorism may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.

Costs of compliance with environmental, climate change and endangered species laws are significant and the costs of compliance with new and emerging laws and regulations and the occurrence of associated liabilities could adversely

affect PSE’s results of operations. PSE’s operations are subject to extensive federal, state and local laws and regulations relating to environmental issues, including air emissions and climate change, endangered species protection, remediation of contamination, avian protection, waste handling and disposal, decommissioning, water protection and siting new facilities. To fulfill these legal requirements, PSE must spend significant sums of money to comply with these measures including resource planning, remediation, monitoring, analysis, mitigation measures, pollution control equipment and emissions related abatement and fees. New environmental laws and regulations affecting PSE’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to PSE or its facilities. Compliance with these or other future regulations could require significant expenditures by PSE and adversely affect PSE financially. In addition, PSE may not be able to recover all of its costs for such expenditures through electric and natural gas rates, in a timely manner, at current levels in the future.

Under current law, PSE is also generally responsible for any on-site liabilities associated with the environmental condition of the facilities that it currently owns or operates or has previously owned or operated. The occurrence of a material environmental liability or new regulations governing such liability could result in substantial future costs and have a material adverse effect on PSE’s results of operations and financial condition. Specific to climate change, Washington State has adopted both renewable portfolio standards and GHG legislation, including CETA, and PSE anticipates full compliance with these requirements.

PSE's inability to adequately develop or acquire the necessary infrastructure to comply with new and emerging laws and regulations could have a material adverse impact on our business and results of operations. Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain various regulatory approvals create uncertainty surrounding our energy resource portfolio. The current abundance of low, stably priced natural gas, together with environmental, regulatory, and other concerns surrounding coal-fired generation resources, fossil fuel infrastructure bans, and energy resource portfolio requirements, including those related to renewables development and energy efficiency measures, create strategic challenges as to the appropriate generation portfolio and fuel diversification mix.

PSE depends on its work force and third party vendors to perform certain important services and may be negatively affected by its inability to attract and retain professional and technical employees or the unavailability of vendors. PSE is subject to workforce factors, including but not limited to loss or retirement of key personnel and availability of qualified personnel. PSE’s ability to implement a workforce succession plan is dependent upon PSE’s ability to employ and retain skilled professional and technical workers. Without a skilled workforce, PSE’s ability to provide quality service to PSE’s customers and to meet regulatory requirements could affect PSE’s earnings. Also, the costs associated with attracting and retaining qualified employees could reduce earnings and cash flows.

PSE continues to be concerned about the availability of skilled workers for special complex utility functions. PSE also hires third party vendors to perform a variety of normal business functions, such as power plant maintenance, data warehousing and management, electric transmission, electric and natural gas distribution construction and maintenance, certain billing and

RISKS RELATING TO PUGET ENERGY'S AND PSE'S FINANCING

The Company's business is dependent on its ability to successfully access capital. The Company relies on access to internally generated funds, bank borrowings through multi-year committed credit facilities and short-term money markets as sources of liquidity and longer-term debt markets to fund PSE's utility construction program and other capital expenditure requirements of PSE. If Puget Energy or PSE are unable to access capital on reasonable terms, their ability to pursue improvements or acquisitions, including generating capacity, which may be necessary for future growth, could be adversely affected. Capital and credit market disruptions, a downgrade of Puget Energy's or PSE's credit rating or the imposition of restrictions on borrowings under their credit facilities in ~~states where~~ the ~~Clean Power Plan~~event of a deterioration of financial ratios, may increase Puget Energy's and PSE’s cost of borrowing or adversely affect the ability to access one or more financial markets.

The amount of the Company's debt could adversely affect its liquidity and results of operations. Puget Energy and PSE have short-term and long-term debt, and may incur additional debt (including secured debt) in the future. Puget Energy has ~~been stayed,~~access to a multi-year $800.0 million revolving credit facility, secured by substantially all of its assets, which has a maturity date of October 25, 2023. There was $24.1 million outstanding under the facility as of December 31, 2019. Puget Energy's credit facility includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.3 billion. In October 2018, Puget Energy entered into a 3-year $150 million term loan agreement with a small group of banks. Subsequently, in April 2019, the amount of the loan was increased to $174.0 million. Separately, Puget Energy entered into a 3 year, $210.0 million term loan agreement with a small group of banks in September 2019. PSE also has a separate credit facility, which provides PSE with access to $800.0 million in short-term borrowing capability, and includes an expansion feature that could, upon the banks' approval, increase the size of the facility to $1.4 billion. The PSE credit facility matures on October 25, 2023. As of December 31, 2019, no amounts were drawn and outstanding under the PSE credit facility. In addition, Puget Energy has issued $1.8 billion in senior secured notes, whereas PSE, as of December 31, 2019, had approximately $4.4 billion outstanding under first mortgage bonds, pollution control bonds and senior notes. The Company's debt level could have important effects on the business, including but not limited to:

•Making it difficult to satisfy obligations under the debt agreements and increasing the risk of default on the debt obligations;

•Making it difficult to fund non-debt service related operations of the business; and

•Limiting the Company's financial flexibility, including its ability to borrow additional funds on favorable terms or at all.

A downgrade in Puget Energy’s or PSE’s credit rating could negatively affect the ability to access capital, the ability to hedge in wholesale markets and the ability to pay dividends. Although neither Puget Energy nor PSE has any rating downgrade provisions in its credit facilities that would accelerate the maturity dates of outstanding debt, a downgrade in the Companies’ credit ratings could adversely affect the ability to renew existing or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy’s and PSE’s facilities, the borrowing spreads over the London Interbank Offered Rate (LIBOR) and commitment fees increase if their respective corporate credit ratings decline. A downgrade in commercial paper ratings could increase the cost of commercial paper and limit or preclude PSE’s ability to issue commercial paper under its current programs.

Any downgrade below investment grade of PSE’s corporate credit rating could cause counterparties in the wholesale electric, wholesale natural gas and financial derivative markets to request PSE to post a letter of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other mutually agreeable security, all of which would expose PSE to additional costs.

PSE may not declare or make any dividend distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0.

Changes in the method for determining LIBOR and the potential replacement of LIBOR may affect our credit facilities and the interest rates on such borrowings. LIBOR, the London interbank offered rate, is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. Puget Energy and PSE’s credit facilities allow Puget Energy or PSE, respectively to borrow at the bank's prime rate or to make floating rate advances at LIBOR plus a spread that is based upon Puget Energy’s or PSE's credit rating, respectively.

On July 27, 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR announced that it intends to phase out LIBOR by the end of 2021. It is unclear if at ~~all.~~ that time LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If the method for calculation of LIBOR changes, if LIBOR is no longer available or if lenders have increased costs due to changes in LIBOR, Puget Energy or PSE may suffer from potential increases in interest rates on any borrowings. Further, Puget Energy or PSE may need to renegotiate our credit facilities that utilize LIBOR as a factor in determining the interest rate to replace LIBOR with the new standard that is established.

The Company may be negatively affected by unfavorable changes in the tax laws or their interpretation. The Company’s tax obligations include income, real estate, public utility, municipal, sales and use, business and occupation and employment-related taxes and ongoing audits related to these taxes. Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the IRS or other taxing jurisdiction could have a material adverse impact on the Company’s financial statements. The tax law, related regulations and case law are inherently complex. The Company must make judgments and interpretations about the application of the law when determining the provision for taxes. These judgments may include reserves for potential ~~impacts~~adverse outcomes regarding tax positions that may be subject to challenge by the taxing authorities. Disputes over interpretations of tax laws may be settled with the taxing authority in examination, upon appeal or through litigation.

In particular, the Tax Cuts and Jobs Act which was enacted in December 2017 introduced significant permanent and temporary changes to the federal tax code. These changes include a tax rate change from 35.0% to 21.0%, the exclusion of utility businesses from claiming bonus depreciation, the limitation of interest deductibility by non-utility businesses, in addition to numerous other changes.

Poor performance of pension and postretirement benefit plan investments and other factors impacting plan costs could unfavorably impact PSE’s cash flow and liquidity. PSE provides a defined benefit pension plan and postretirement benefits to certain PSE employees and former employees. Costs of providing these benefits are based, in part, on the value of the plan’s assets and the current interest rate environment and therefore, adverse market performance or low interest rates could result in lower rates of return for the investments that fund PSE’s pension and postretirement benefits plans and could increase PSE’s funding requirements related to the pension plans. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase PSE's funding requirements related to the pension plans. Any contributions to PSE’s plans in 2020 and beyond as well as the timing of the recovery of such contributions in GRCs could impact PSE’s cash flow and liquidity.

Potential legal proceedings and claims could increase the Company’s costs, reduce the Company’s revenue and cash flow, or otherwise alter the way the Company conducts business. The Company is, from time to time, subject to various legal proceedings and claims. Any such claims, whether with or without merit, could be time-consuming and expensive to defend and could divert management’s attention and resources. While management believes the Company has reasonable and prudent insurance coverage and accrues loss contingencies for all known matters that are probable and can be reasonably estimated, the Company cannot assure that the outcome of all current or future litigation will not have a material adverse effect on the Company and/or its results of operations.

RISKS RELATING TO PUGET ENERGY'S CORPORATE STRUCTURE

Puget Energy's ability to pay dividends may be limited. As a holding company with no significant operations of its own, the primary source of funds for the repayment of debt and other expenses, as well as payment of dividends to its shareholder, is cash dividends PSE pays to Puget Energy. PSE is a separate and distinct legal entity and has no obligation to pay any amounts to Puget Energy, whether by dividends, loans or other payments. The ability of PSE to pay dividends or make distributions to Puget Energy, and accordingly, Puget Energy’s ability to pay dividends or repay debt or other expenses, will depend on PSE’s earnings, capital requirements and general financial condition. If Puget Energy does not receive adequate distributions from PSE, it may not be able to meet its obligations or pay dividends.

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. In addition, beginning February 2009, pursuant to the terms of the Washington ~~Clean Air Rule are described, below.~~

~~Washington Clean Air Rule~~

~~The CAR was adopted~~Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio calculated on September 15, 2016 in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. CAR sets a ~~cap on emissions associated with covered entities, which decreases over time approximately 5% every three years. Entities must reduce their carbon emissions,~~regulatory basis is 44.0% or ~~purchase emission reduction units (ERUs), as defined under the rule, from others.~~

CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. CAR regulates the emissions of natural gas utilities' 1.2 million customers across the state, addingbelow, except to the ~~cost~~extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE's ability to declare or make any distribution is limited by its' corporate credit/issuer rating and EBITDA to interest ratio, as previously discussed above. The common equity ratio, calculated on a regulatory basis, was 48.4% at December 31, 2019, and the EBITDA to interest expense was 5.3 to 1.0 for the twelve-months ended December 31, 2019.

PSE’s ability to pay dividends is also limited by the terms of ~~natural gas for homes and businesses,~~its credit facilities, pursuant to which ~~may increase costs~~PSE is not permitted to ~~PSE customers.~~

~~On September 27, 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed an action~~pay dividends during any Event of Default (as defined in the ~~U.S. District Court for~~facilities), or if the ~~Eastern District~~payment of ~~Washington challenging CAR. On September 30, 2016, the four companies filed a similar challenge to CAR~~dividends would result in ~~Thurston County Superior Court. While awaiting the outcome~~an Event of ~~the pending litigation, the Company has undertaken steps~~Default, such as failure to comply with certain financial covenants.

Challenges relating to the ~~first compliance period~~construction or future operation of ~~CAR,~~the Tacoma LNG facility could adversely affect the Company’s operations. PSE and Puget Energy’s subsidiary, Puget LNG, currently are constructing the Tacoma LNG facility at the Port of Tacoma, a jointly owned facility intended to provide peak-shaving services to PSE’s natural gas customers, and to provide LNG as fuel primarily to the maritime market. Puget LNG has entered into one fuel supply agreement with a maritime customer, and is marketing the facility’s expected output to other potential customers. Scheduled to be completed in 2021, delays in the facility’s construction and operation or in its ability to timely deliver fuel to customers could expose Puget LNG to damages under one or more fuel supply contracts, which ~~begins January~~could unfavorably impact Puget Energy’s return on investment.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

The principal electric generating plants and underground natural gas storage facilities owned by PSE are described under Item 1, ~~2017.~~Business – Electric Supply and Natural Gas Supply. PSE owns its transmission and distribution facilities and various other properties. Substantially all properties of PSE are subject to the liens of PSE’s mortgage indentures. The Company’s corporate headquarters is housed in a leased building located in Bellevue, Washington.

ITEM 3. LEGAL PROCEEDINGS

For ~~more~~ information on litigation or legislative rulemaking proceedings, see ~~Item 1, "Business, Recent and Future Environmental Law and Regulation", and~~ Note ~~14,~~15, "Litigation" to the consolidated financial statements included in Item 8 of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of the outstanding shares of Puget Energy’s common stock, the only class of common equity of Puget Energy, are held by its direct parent Puget Equico LLC (Puget Equico), which is an indirect wholly-owned subsidiary of Puget Holdings, and are not publicly traded. The outstanding shares of PSE’s common stock, the only class of common equity of PSE, are held by Puget Energy and are not publicly traded.

The payment of dividends on PSE common stock to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s mortgage indentures in addition to terms of the Washington Commission merger order. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission as well as by the terms of its credit facilities. For further discussion, see Item 1A, "Risk Factors"- Risks Relating to Puget Energy’s Corporate Structure and Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included in this report.

From time to time, when deemed advisable and permitted, PSE and Puget Energy pay dividends on its common stock. During ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, PSE paid dividends to its parent, Puget Energy, and Puget Energy paid dividends to its parent, Puget Equico, in the amounts shown in Puget Energy's and PSE's Consolidated Statements of Common Shareholder's Equity, included in this Form 10-K.

ITEM 6. SELECTED FINANCIAL DATA

The following tables show selected financial data. This information should be read in conjunction with the audited consolidated financial statements and the related notes found in Item 8, "Financial Statements and Supplementary Data" along with the information included in ~~Items~~Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operation" ~~and Item 8, "Financial Statements and Supplementary Data"~~ of this Form ~~10-K, respectively.~~10-K.


Puget Energy
Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2019		2018		2017		2016		2015
Operating revenue	$	3,401,130	$	3,346,496	$	3,460,276	$	3,164,301	$	3,092,700
Operating income	519,008		554,058		739,106		765,474		671,925
Net income	210,708		235,622		175,194		312,899		241,179

Total assets at year-end	$	14,659,863	$	14,098,861	$	13,690,789	$	13,266,380	$	12,814,254
Long-term debt	5,920,325		5,672,491		5,207,929		5,104,073		5,077,518
Junior subordinated notes	—		—		250,000		250,000		250,000
Finance lease obligations	1,480		1,315		1,129		645		378
Operating lease obligations	190,189		—		—		—		—


Puget Sound Energy
Summary of Operations	Year Ended December 31,
(Dollars in Thousands)	2019		2018		2017		2016		2015
Operating revenue	$	3,401,130	$	3,346,496	$	3,460,276	$	3,164,618	$	3,093,258
Operating income	522,615		557,136		740,595		770,552		656,138
Net income	292,924		317,162		320,054		380,581		304,189

Total assets at year-end	$	12,625,045	$	12,097,523	$	11,731,706	$	11,297,080	$	10,799,513
Long-term debt	4,336,142		3,894,860		3,499,911		3,497,298		3,494,362
Junior subordinated notes	—		—		250,000		250,000		250,000
Finance lease obligations	1,480		1,315		1,129		645		378
Operating lease obligations	190,189		—		—		—		—

Puget Energy
Summary of Operations Year Ended December 31,
(Dollars in Thousands) 2016 2015 2014 2013 2012
Operating revenue $ 3,164,301
$ 3,092,700
$ 3,113,171
$ 3,187,297
$ 3,215,156
Operating income 785,384
671,925
577,851
755,160
715,535
Net income 312,899
241,179
171,835
285,728
273,821

Total assets at year end $ 13,266,380
$ 12,814,254
$ 12,673,603
$ 12,820,571
$ 12,781,838
Long-term debt 5,104,073
5,077,518
4,831,608
4,982,476
5,083,200
Junior subordinated notes 250,000
250,000
250,000
250,000
250,000
Capital lease obligations 645
378
9,473
17,051
24,629

Puget Sound Energy
Summary of Operations Year Ended December 31,
(Dollars in Thousands) 2016 2015 2014 2013 2012
Operating revenue $ 3,164,618
$ 3,093,258
$ 3,116,123
$ 3,187,335
$ 3,216,259
Operating income 774,993
656,138
568,693
735,574
692,989
Net income 380,581
304,189
236,614
356,129
356,170

Total assets at year end $ 11,297,080
$ 10,799,513
$ 10,581,415
$ 10,667,830
$ 10,559,956
Long-term debt 3,497,298
3,494,362
3,351,259
3,513,258
3,513,258
Junior subordinated notes 250,000
250,000
250,000
250,000
250,000
Capital lease obligations 645
378
9,473
17,051
24,629

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, ~~named~~ Puget LNG, LLC (Puget LNG)~~. Puget LNG was formed on November 29, 2016, and~~, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma ~~LNG~~liquefied natural gas (LNG) facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including ~~Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust,~~ the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation ~~and~~(BCI), the Alberta Investment Management ~~Corporation.~~Corporation (AIMCo), Ontario Municipal Employee Retirement System (OMERS) and PGGM Vermogensbeheer B.V. The sale of previous owners', Macquarie Infrastructure Partners and Macquarie Capital Group Limited, shares to OMERS, PGGM Vermogensbeheer B.V., AIMCo and BCI was approved by various federal and state agencies, including that of the Washington Utilities and Transportation Commission (Washington Commission), and closed on April 17, 2019. Puget Energy and PSE are collectively referred to herein as “the Company.”

PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.

Factors affecting PSE's performance are set forth in this “Overview” section, as well as in other sections of the Management's Discussion and Analysis.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as return on equity (ROE) excluding unrealized gains and losses on derivative instruments (net income plus unrealized losses and/or minus unrealized gains on derivative instruments divided by average common equity) that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a departure from GAAP presentation. The Company believes that its return on average of monthly averages (AMA) equity, also a non-GAAP

measure, is a more suitable metric for comparing ROE across years and is a more accurate metric for assessing and evaluating ROE performance against the Company's authorized regulated ROE. The AMA equity is not intended to represent the regulated equity. PSE's ROE may not be comparable to other companies' ROE measures. Furthermore, this measure is not intended to replace ROE ~~(net~~(GAAP net income divided by GAAP average common equity) ~~as determined in accordance with GAAP~~ as an indicator of operating performance.

The following table presents PSE’s ROE, its return on AMA equity and ~~it's~~its authorized regulated ROE for ~~2016~~2019 and ~~2015:~~2018:


	2016			2015				2019					2018
(Dollars in Thousands)	Earnings	Average Common Equity	Return on Equity	Earnings	Average Common Equity	Return on Equity	(Dollars in Thousands)	Earnings	Average Common Equity	Return on Equity	Earnings	Average Common Equity	Return on Equity
Return on equity	$380,581	$3,426,620	11.1%	$304,189	$3,320,861	9.2%	Return on equity	$292,924	$3,878,302	7.6%	$317,162	$3,654,524	8.7%
Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	(54,467)	—	*	(8,247)	—	*	Less/Plus: Unrealized gains and losses on derivative instruments, after-tax	2,823	—	*	(32,913)	—	*
Less: Equity adjustments¹	—	177,196	*	—	228,267	*
Less/Plus: Equity adjustments¹							Less/Plus: Equity adjustments¹	—	179,517	*	—	179,852	*
Plus: Impact of average of monthly average (AMA)	—	57,212	*	—	34,585	*	Plus: Impact of average of monthly average (AMA)	—	(48,247)	*	—	18,075	*
Return on AMA equity	$326,114	$3,661,028	8.9%	$295,942	$3,583,713	8.3%	Return on AMA equity	$295,747	$4,009,572	7.4%	$284,249	$3,852,451	7.4%
Authorized regulated return on equity	*		9.8%	*		9.8%
Authorized regulated return on equity²							Authorized regulated return on equity²			9.5%			9.5%

_______________


¹	Equity adjustments are related to removing the impacts of accumulated other comprehensive income (AOCI), subsidiary retained earnings, retained earnings of derivative instruments, and decoupling 24-month revenue reserve.


^*	~~Not meaningful and/or applicable.~~

^1.Equity adjustments are related to removing the impacts of accumulated other comprehensive income (AOCI), subsidiary retained earnings, retained earnings of derivative instruments, and decoupling 24-month revenue reserve.

^2.The authorized regulated return on equity rate is 9.5% effective December 19, 2017, per the approved general rate case (GRC).

*Not meaningful and/or applicable.

The Company’s ~~2016~~2019 return on AMA equity was ~~8.9%~~7.4%, which is lower than the authorized regulated ROE primarily due to the following:

•Regulated equity (rate base ~~time's~~multiplied by equity percent) was ~~$360.0~~$351.6 million lower than AMA equity for the year ended December 31, ~~2016. The variance was primarily driven by the impact on rate base of the deferred tax liability for utility, plant and equipment.~~2019. The impact on ROE for this variance was ~~1.0%~~negative 0.8%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last general rate case (GRC).

•Depreciation expense was ~~$10.5~~$90.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, ~~2016.~~2019, for an impact on ROE of negative 2.3%.

~~Partially offsetting the above was net revenue from below the line activities which totaled $4.3 million.~~

The Company’s ~~2015~~2018 return on AMA equity was ~~8.3%~~7.4%, which is lower than the authorized regulated ROE primarily due to the following:

•Regulated equity (rate base ~~time's~~multiplied by equity percent) was ~~$256.0~~$379.9 million lower than AMA equity for the year ended December 31, 2015. The variance was primarily driven by the unanticipated impacts on rate base of the deferred tax liability for utility, plant and equipment and lower than anticipated capital spending due to slower than anticipated growth in PSE’s service territory.2018. The impact on ROE for this variance was ~~1.1%~~negative 0.9%. The variance was primarily driven by investment in items that do not earn a return or earn a return that is less than the authorized ROE. Such items include investment in construction work in progress and growth in rate base since the last GRC.

~~Utility margins were $6.1 million lower than allowed in rates for the year ended December 31, 2015 due to the impacts of warmer than normal weather conditions.~~

•Depreciation expense was ~~$5.2~~$50.7 million higher than the amount allowed in rates on a pre-tax basis for the year ended December 31, ~~2015.~~2018, for an impact on ROE of negative 1.3%.

Factors and Trends Affecting PSE’s Performance

PSE’s ongoing regulatory requirements and operational needs necessitated the investment of substantial capital in ~~2016~~2019 and will continue to do so in future years. Because PSE intends to seek recovery of such investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The principal business, economic and other factors that affect PSE’s operations and financial performance include:

•The rates PSE is allowed to charge for its services;

•PSE’s ability to recover power costs that are included in rates which are based on volume;

•Weather conditions, including the impact of temperature on customer load; the impact of extreme weather events on budgeted maintenance costs; meteorological conditions such as snow-pack, ~~affecting hydrological conditions;~~stream-flow and wind-speed which affect power generation, supply and price;

•The effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

•Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;

•PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;

•Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of ~~return;~~return (ROR);

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

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

•Wholesale commodity prices of electricity and natural gas;

•Increasing capital expenditures with additional depreciation and amortization;

~~Bonus depreciation~~•Failure to complete capital projects on schedule and within budget or the ~~impact~~abandonment of capital projects, either of which could result in the Company’s inability to recover project costs;

•Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate ~~base;~~base and customer rates;

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

•Federal, state, and local ~~taxes.~~taxes;

•Employee workforce factors, including potential strikes, work stoppages, transitions in senior management, and loss or retirement of key personnel and availability of qualified personnel

•The effectiveness of PSE’s risk management policies and procedures;

•Cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer, employee, or Company information;

•Acts of war or terrorism.

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2019 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. ~~Accordingly,~~Absent a resolution for the impact of lag and attrition, the Company will need to seek rate relief through a rate case on a regular and frequent basis in the foreseeable future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of ~~cost effective,~~cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that ~~an operating expense or~~a capital investment ~~does~~is not ~~meet the~~ reasonable ~~and~~or prudent, ~~standards,~~ the costs (including return on any resulting rate base) related to such ~~operating expense or~~ capital investment may be disallowed, partially or entirely, and not recovered in rates.

During 2013, PSE completed an ERF, which was a limited scope rate proceeding, and established a decoupling mechanism for natural gas operations and electric transmission, distribution and administrative costs. The ERF proceeding established baseline rates on which the decoupling mechanism will operate during the rate plan period. The ERF also established a property tax tracker mechanism in which any difference between amounts in rates and property tax payments will be deferred and recovered in an annual filing based on the annual cash payments for the year.

The decoupling mechanism allows PSE to recover costs on a per customer basis rather than on a consumption basis. Included in the decoupling petition was a rate plan that allows PSE an opportunity to earn its authorized rate of return without the need for another GRC process during the rate plan period. The rate plan included predetermined annual increases to PSE’s allowed electric and natural gas revenue. This plan required PSE to file a GRC no later than April 1, 2016 which date was later extended by the Washington Commission to January 17, 2017.

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

PSE. The effects of achieving these standards will, however, have only a slight negative impact on natural gas business financial performance due to the natural gas business being almost fully decoupled.

General Rate Case Filing

Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in ColstripColstrip Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC.

PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings". PSE also requested that the Washington Commission offset the regulatory liabilities for PTCs and Grants against the future cost of Colstrip shutdown and remediationoverall request in order to ~~prevent future~~address the expected regulatory lag in the rate ~~increases~~year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to ~~customers. Additionally, PSE’s~~pass back the amounts over four years.On September 17, 2019, PSE filed a supplemental filing ~~contains requests for two new mechanisms to address regulatory lag. PSE has~~in the GRC, which provided updates as discussed in our original filing, but did not impact the requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a general rate case proceeding. PSE also requested approval to establish an electric CRM similar to its existing natural gas CRM which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

~~Decoupling Filings~~

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to itsoverall electric and natural gas ~~operating revenues related~~rate increases, return on equity or overall rate of return as originally filed.On January 15, 2020, PSE filed rebuttal testimony which included a reduction to ~~electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers~~the requested return on equity to ~~mitigate~~9.5%, which decreased the ~~effects~~rate of ~~weather, conservation impacts and changes in usage patterns per customer. As a result, these~~return to 7.48%.The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

For further details regarding the 2019 GRC filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.

Expedited Rate Filing

On November 7, 2018, PSE filed an ERF with the Washington Commission. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms. The settlement agreement was filed on January 30, 2019. On February 21, 2019, the Commission approved the settlement with one condition. The settlement requires that PSE pass back the deferred balance associated with the tax over-collection of $34.6 million from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

For further details regarding the 2018 ERF filing, see Note 4, "Regulations and Rates" to the consolidated financial statements included in Item 8 of this report.

Washington Commission Tax Deferral Filing

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

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

Effective Date

Average Percentage Increase (Decrease) in Rates

Increase (Decrease) in Revenue (Dollars in Millions)

Electric:

May 1, 2018

(3.4)%

$(72.9)

Natural Gas:

May 1, 2018

(2.7)

(23.6)

Decoupling Filings

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis ~~regardless~~and electric fixed production energy costs will now be decoupled and recovered on the basis of ~~actual consumption levels. The~~a fixed monthly amount. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy ~~supply~~ costs ~~which are part of the PCA and PGA mechanisms, are not included~~can also be changed in a power cost only rate case (PCORC).

Other changes to the decoupling ~~mechanism. The revenue recorded under~~methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling ~~mechanisms~~mechanism going forward. The rate cap, which limits the amount of previously deferred revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.remain at 3.0% for electric customers. The decoupling mechanism ~~will end on December 31, 2017 unless the continuation of the requested~~is to be reviewed again in PSE's first GRC filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism ~~is approved in PSE’s 2017 GRC which PSE filed on January 13, 2017. Decoupling over~~over- and ~~under~~under- collections will still be collectible or refundable after ~~December 31, 2017,~~this effective date even if the decoupling mechanism is not extended.

On ~~April 28, 2016,~~February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ~~request to change rates under its~~ERF filing. As part of this settlement agreement, electric and natural gas ~~decoupling mechanisms, effective May 1, 2016. The overall~~allowed delivery revenue per customer was updated to reflect changes ~~represent a rate increase for~~in the approved revenue requirement. For electric, customers of $20.8 million, or 1.0%, annually, and a rate increase for natural gas customers of $25.4 million, or 2.8%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas businesses in 2016 and 2015. As a result, PSE recorded a reduction in electric decoupling deferral and revenue of $11.2 million and $16.3 million, respectively, and a reduction in natural gas deferral and revenue of $2.1 million and $9.2 million, respectively. This was reflected as a reductionthere were no changes to the ~~electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0%~~ annual ~~decoupling related cap~~allowed fixed power cost revenue. The changes took effect on increases in total revenue. This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2016 rate increase is $28.7 million for natural gas revenue that was accrued throughMarch 1, 2019.

On December 31, ~~2015. This amount may be included in customer rates beginning in May 2017, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.~~

~~Due to the 3.0% cap on annual decoupling increases noted above and the growing size of decoupling deferrals,~~2019, PSE performed an analysis ~~as of December 31, 2016~~ to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of ~~December 31, 2016.~~the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated ~~$19.6~~that all of electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2019 decoupling revenue.

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)¹
Electric:
May 1, 2019	0.9%	$20.6
May 1, 2018	(1.1)	(25.2)
May 1, 2017	2.0	41.9
Natural Gas:
May 1, 2019	(5.3)%	$(45.9)
May 1, 2018	1.7	15.9
May 1, 2017	2.4	22.4

___________________

1.There were no excess earnings offsetting the increase in revenue for either electric or natural gas effective May 1, 2019, The increase in revenue is net of reductions from excess earnings of $10.0 million for electric and ~~$1.3~~$4.9 million for natural gas effective May 1, 2018, and $11.9 million for electric and $2.2 million for natural gas effective May 1, 2017.

Electric Rates

Power Cost Adjustment Mechanism

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

Effective January 1, 2017, the following graduated scale is used in the PCA mechanism:


	Company’s Share									Customers' Share
Annual Power Cost Variability	Over		Under				Over			Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%		—	%
Over or Under Collected by between $17 million - $40 million	35		50		65			50
Over or Under Collected beyond $40 + million	10		10		90			90

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

For the year ended December 31, 2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to customers. This compares to an under recovery of allowable costs of $3.5 million for the year ended December 31, 2018, of which no amounts were apportioned to customers. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a narrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a transmission line, which contributed to a liquidity crisis at Mid-C and resulted in high market power prices; and (iv) The relative prices of natural gas and ~~electric decoupling~~power, which reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.

Power Cost Adjustment Clause Filing

PSE updated its rates under Schedule 95 its Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract.

The following table sets forth power cost adjustment clause filing approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue ~~respectively, will not be collected within 24 months. Therefore, PSE did not recognize this portion~~based on the effective dates:

Effective Date

Average

Percentage

Increase (Decrease)

in Rates

Increase (Decrease)

in Revenue

(Dollars in Millions)

May 1, 2019

(1.2)%

$(24.9)

Electric Conservation Rider

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	(0.9)%	$(17.5)
May 1, 2018	(0.8)	(18.0)
May 1, 2017	0.7	16.5

Electric Property Tax Tracker Mechanism

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	(0.2)%	$(5.1)
May 1, 2018	(0.1)	(1.3)
May 1, 2017	(0.04)	(0.9)

Federal Incentive Tracker Tariff

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


Effective Date	Average Percentage Increase (Decrease) in Rates from prior year	Total credit to be passed back to eligible customers (Dollars in Millions)
January 1, 2020	(0.04)%	$(37.8)
January 1, 2019	0.1	(38.7)
May 1, 2018	0.4	(40.1)
January 1, 2018	0.2	(48.2)
January 1, 2017	0.3	(51.7)

Residential Exchange Benefit

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Total credit to be passed back to eligible customers (Dollars in Millions)
October 12, 2019	0.01%	$(81.8)
October 1, 2017	(0.6)	(80.8)

Natural Gas Rates

Natural Gas 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, 2019	0.8%	$7.0
November 1, 2018	0.5	5.0
November 1, 2017	0.5	4.9

Purchased Gas Adjustment

On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to purchased gas adjustment (PGA) rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of ~~decoupling revenue. However, once it is determined~~the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to ~~be collectible within 24 months, it~~higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be ~~recognized.~~from May 2019 through April 2020.

On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021.

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
November 1, 2019	13.4%	$118.3
May 1, 2019	6.3	54.0
November 1, 2018	(10.9)	(98.4)
November 1, 2017	(3.3)	(30.8)

Natural Gas Property Tax Tracker Mechanism

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, 2019	(0.2)%	$(1.6)
May 1, 2018	(0.2)	(2.2)
May 1, 2017	(0.1)	(1.1)

Natural Gas Conservation Rider

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


Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)
May 1, 2019	0.1%	$1.1
May 1, 2017	(0.1)	(1.0)

Other Proceedings

Microsoft Special Contract

Following discussions between PSE, the Microsoft Corporation, and others, and after completing a negotiated regulatory process, the Washington Commission issued an order in July 2017 approving a special contract between PSE and Microsoft ~~have been~~relating to retail access for Microsoft loads currently being served under PSE’s electric Schedule 40. The special contract includes the following conditions: (i) Microsoft must exceed Washington State’s current renewable portfolio standards, (ii) the remainder of power sold to Microsoft must be carbon free, (iii) there will be no reduction in ~~conversations~~Microsoft's funding of PSE’s conservation programs, (iv) Microsoft paid a transition fee that was a straight pass-through to ~~develop a mechanism to provide open access~~customers and (v) Microsoft will fund enhanced low-income support. Microsoft began taking service ~~to satisfy sustainability objectives. To that end, PSE filed a tariff that has strong limitations~~under the special contract on April 1, 2019, after meeting the eligibility ~~including a stranded cost amount that Microsoft would be required to pay in order to keep all other customers whole. The proposed tariff is currently suspended while~~requirements under the ~~Washington Commission undertakes discovery.~~special contract.

Voluntary Long-Term Renewable Energy

OnEffective September ~~28,~~ 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy ~~product, effective September 30, 2016.~~product. This ~~will provide~~provides customers with ~~energy choices~~electric generation resource options to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE ~~will initially offer~~offered this service, Green Direct, to larger customers (aggregated annual loads greater than ~~10,000,000 kWh)~~10,000 MWh) and government customers.

~~Electric Rates~~

~~Power Cost Adjustment Mechanism~~

~~PSE~~ The initial resource option offered under this rate schedule is a new wind generation facility with the capacity of approximately 136.8 MW currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forthunder construction in the ~~PCA mechanism~~region by a developer under contract to PSE. The project is fully subscribed and is expected to begin generating power in 2020. Twenty-one customers will ~~trigger a surcharge or refund when~~receive the ~~cumulative deferral trigger is reached.~~

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

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

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

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

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

Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return 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~~anticipated output of the ~~requirement that a GRC must be filed within three months after rates are approved in a PCORC;~~project.

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

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

Pursuant to the PCA Settlement approved on August 7, 2015, effective January 1, 2017, PSE's fixed costs are no longer tracked in PSE's PCA mechanism. Accordingly, on September 30, 2016, PSE filed an accounting petition with the Washington Commission which requests deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested is January 1, 2017 through December 31, 2017 when rates are in effect from PSE's next GRC. The Commission issued Order No. 01 on November 10, 2016 approving PSE’s accounting petition.

~~Federal Incentive Tracker Tariff~~

~~On December 22, 2016,~~In July 2018, the Washington Commission approved a second phase of the ~~annual true-up~~Green Direct product. The phase 2 offering will be a blend of the phase 1 wind and ~~rate filing to PSE's Federal Incentive Tracker Tariff, with an effective date of January 1, 2017. The true-up filing resulted in~~ a ~~total credit of $51.7 million~~solar project to be ~~passed back~~built in Washington. Phase 1 customers will receive wind through 2020; and then are expected to ~~eligible~~receive the blended energy in 2021. An additional twenty customers ~~over the twelve months beginning January 1, 2017. The total credit includes $38.1 million which represents the pass-back of grant amortization and $13.6 million represents the pass~~will start receiving energy through ~~of interest, in addition to a minor true-up associated with the 2016 rate period. This filing represents an overall average rate increase of 0.3% annually.~~

~~Power Cost Update Compliance Filing~~

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

~~Electric Property Tax Tracker Mechanism~~

On April 28, 2016, the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism, effective May 1, 2016. The approved rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $5.7 million, or 0.3% annually.

~~Electric Conservation Rider~~

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

On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its electric conservation rider mechanism, effective May 1, 2016. The approved rate change incorporates estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period. This represents a rate decrease for electric customers of $11.7 million, or 0.5% annually.

~~Natural Gas Rates~~

~~Purchased Gas Adjustment~~

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

~~Cost Recovery Mechanism~~

On October 27, 2016, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2016. The purpose of this filing is to recover capital costs related to enhancing the safetyphase 2 of the ~~natural gas distribution system. The impact to the CRM rates is an annual revenue increase of $5.6 million, or 0.6% annually.~~program, likely by 2021.

~~Natural Gas Property Tax Tracker Mechanism~~

On April 28, 2016, the Washington Commission approved PSE's request to change rates under its natural gas property tax tracker mechanism, effective May 1, 2016. This represents a rate increase for natural gas customers of $3.5 million or 0.4% annually.

~~Natural Gas Conservation Rider~~

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

On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its natural gas conservation rider mechanism, effective May 1, 2016. The approved rate change reflects estimated program year expenditures as well as a true up for actual costs and collections for the conservation program for the prior period. This represents a rate increase for natural gas customers of $2.9 million, or 0.3% annually.

For additional information, see ~~Business, "Regulation and Rates" included in Item 1 of this report and~~ Note 3,4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.

Access to Debt Capital

PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. PSE's credit facilities mature in 2019 and Puget Energy's senior secured credit facility matures in 2018. See discussion on credit facilities in Part II in Item 7, “Financing Program - Puget Sound Energy - Credit Facilities and Puget Energy - Credit Facility".

Regulatory Compliance Costs and Expenditures

PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, natural gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation by-products such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend a significant ~~amounts~~amount of resources to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates on measures including ~~but not limited to,~~ resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.

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

Other Challenges and Strategies

Competition

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

Results of Operations

Puget Sound Energy

The following discussion should be read in conjunction with the audited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE’s results of operations for the years ended December 31, ~~2016~~2019, and ~~2015. Set forth below are the consolidated financial results of PSE for the years ended~~ December 31, ~~2016, 2015 and 2014.~~2018.

Non-GAAP Financial Measures – Electric and Natural Gas Margins

The following discussion includes financial information prepared in accordance with GAAP, as well as two other financial measures, electric margin and natural gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that includes adjustments that result in a departure from GAAP presentation. The presentation of electric margin and natural gas margin is intended to supplement an understanding of PSE’s operating performance. Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers in order to ~~maintain electric and natural gas margins to ultimately~~ provide adequate recovery of operating costs, including interest and equity returns. PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Electric Margin

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE’s service territory.

The following ~~table~~chart displays the ~~details of~~changes in PSE’s electric margin ~~changes from periods 2016~~for the years ended December 31, 2018, to ~~2015~~December 31, 2019:

_______________

^*Includes decoupling cash collections, rate of return excess earnings, and ~~periods 2015 to 2014:~~decoupling 24-month revenue reserve.

Electric Margin
Year Ended
December 31,
Dollar Change
Year Ended
December 31,
Dollar Change
(Dollars in Thousands) 2016 2015 2014
Electric operating revenue:
Residential sales $ 1,138,871
$ 1,061,117
$ 77,754
$ 1,003,205
$ 57,912
Commercial sales 872,057
867,786
4,271
824,778
43,008
Industrial sales 113,469
114,223
(754 ) 107,750
6,473
Other retail sales 20,045
20,216
(171 ) 19,707
509
Total retail sales 2,144,442
2,063,342
81,100
1,955,440
107,902
Transportation sales 10,937
10,143
794
9,502
641
Sales to other utilities and marketers 50,124
46,666
3,458
41,680
4,986
Decoupling revenue 29,968
13,630
16,338
25,735
(12,105 )
Other decoupling revenue¹
(21,168 ) (16,634 ) (4,534 ) 5,609
(22,243 )
Other 24,189
11,321
12,868
45,831
(34,510 )
Total electric operating revenues²
2,238,492
2,128,468
110,024
2,083,797
44,671
Minus power costs:

Purchased electricity²
(531,596 ) (499,522 ) (32,074 ) (514,087 ) 14,565
Electric generation fuel²
(215,331 ) (249,907 ) 34,576
(263,493 ) 13,586
Residential exchange²
69,824
112,473
(42,649 ) 129,036
(16,563 )
Total electric power costs (677,103 ) (636,956 ) (40,147 ) (648,544 ) 11,588
Electric margin³
$ 1,561,389
$ 1,491,512
$ 69,877
$ 1,435,253
$ 56,259

Electric Energy Sales
MWh
Residential sales 10,245,326
10,164,703
80,623
10,349,928
(185,225 )
Commercial sales 8,895,950
8,999,068
(103,118 ) 8,900,863
98,205
Industrial sales 1,223,214
1,257,958
(34,744 ) 1,226,588
31,370
Other retail sales 90,753
94,847
(4,094 ) 98,499
(3,652 )
Total energy sales to customers 20,455,243
20,516,576
(61,333 ) 20,575,878
(59.302 )

~~_______________~~


¹	~~Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.~~


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


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

~~2016~~2018 compared to ~~2015~~2019

Electric Operating Revenue

Electric operating revenues increased ~~$110.0~~$41.2 million primarily due to ~~higher residential~~increased transportation and other revenue of $65.0 million, sales to other utilities and marketers of ~~$77.8~~$19.8 million ~~increased deferred~~and decoupling revenue of ~~$16.3~~$2.1 million; partially offset by lower retail sales of $44.3 million and other ~~electric operating~~decoupling revenue of ~~$12.9~~$1.4 million. These items are discussed in detail below:

•Electric retail sales ~~increased $81.1~~ decreased $44.3 million ~~due to increases in rates and residential exchange credits of $86.4 million which was partially offset by $5.6 million due to lower retail electricity usage for non-residential customers.~~

~~Decoupling revenue~~ ~~increased $16.3 million due to the allowed decoupled revenues per customer as compared to volumetric revenues in 2016 compared to 2015.~~

~~Other electric operating revenue~~ ~~increased $12.9 million primarily due to a reduction of amortization of PTC deferral credits of $10.1 million and non-core gas sales of $6.8 million.~~

~~Electric Power Costs~~

~~Electric power costs~~ ~~decreased $40.1 million primarily~~ due to a decrease of ~~$42.6~~$60.7 million in rates partially offset by an increase in retail electricity usage of ~~residential exchange credits,~~0.7%, or $16.4 million, compared to the prior year. The additional usage was due to an increase of ~~$32.1~~residential sales and other retail sales of 2.5% and 1.1%, respectively, which was driven by an increase in heating degree days of 3.5% compared to 2018 and an increase in retail customers of 1.4%. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for rate changes.

•Sales to other utilities and marketers increased $19.8 million due to a 20.8% increase in sales volume and a 1.0% increase in price. During the 1st quarter of 2019, wholesale prices increased 115.7% due to spot power prices at Mid-Columbia that increased to an 18-year high largely driven by record-breaking natural gas prices and there was increase in volumes from an additional 111.8% of combustion turbine (CT) generation or an additional 61.2% CT generation at year to date as a result of favorable heat rates and increased demand for wholesale market power.

•Decoupling revenue increased $2.1 million, primarily attributable to an $8.5 million increase in PCA fixed cost deferral revenues. In the current year, actual PCA revenues declined significantly as a result of lower rates, offset in

part by increased usage as noted above in the retail revenue section. This resulted in current year under collection, as compared to prior year over collection. This increase was partially offset by a $6.3 million decrease in delivery deferral revenues, attributable to a decline in allowed revenues year over year as a result of lower allowed rate per customer.

•Other decoupling revenue decreased $1.4 million, primarily related to earnings in excess of allowed ROR. In 2018, $10.1 million of ~~purchase electricity costs,~~earnings in excess of allowed ROR was passed back to customers, as compared to only $3.5 million in the current year. This decrease of $6.6 million was partially offset by an increase of $4.4 million attributable to lower current period amortization of prior year under collection in 2019 than in 2018. In addition, there was a $1.7 million increase related to GAAP alternative revenue program recognition guidelines. In 2018, there was $0.8 million of revenue that was not anticipated to be collected within 24 months, and therefore was deferred. This amount was recognized in the first quarter of 2019, when the alternative revenue program revenue recognition guidelines were met.

•Transportation and other revenue increased $65.0 million primarily due to an increase in net wholesale natural gas sales of $34.8 million, and an increase in tax reform deferrals for revenue subject to refunds of $38.9 million, partially offset by a decrease in production tax credit (PTC) deferral revenue of ~~$34.5~~$14.9 million for the re-purpose of the PTCs The increase in net wholesale non-core natural gas sales was due to an approximately 28% increase in the average price of the non-core natural gas sold year ended December 31, 2019, compared to year ended December 31, 2018, offset by a 17% decrease in sales volume. Also contributing to the increase in the net amount was an $18.3 million decrease in the cost of the natural gas sold due to the 17% decrease in sales volume, offset by a 6% increase in the average cost of the natural gas sold which was driven by an increase in the average price of non-core natural gas purchases. The higher natural gas prices occurred in late 2018 and peaked in early 2019 and were due to the effects of the late 2018 Enbridge pipeline rupture which led to a decrease in natural gas supply and higher than expected demand due to cold weather during that time.

Electric Power Costs

Electric power costs increased $90.7 million primarily due to an increase of $78.7 million of electric generation fuel ~~expense.~~costs and $13.8 million of purchased electricity costs. These items are discussed in detail below:

•Purchased electricity expense increased ~~$32.1~~$13.8 million primarily due to a ~~$42.3 million~~15.9% increase in ~~long-term firm and market power purchases, $10.0 million increase in PURPA purchases,~~wholesale prices partially offset by ~~$26.3 million related to reduced~~a 11.9% decrease in wholesale electricity purchases. The decrease in purchases was primarily driven by a decrease in hydro purchases at Mid-Columbia of ~~power.~~

~~Electric generation fuel~~ ~~expense decreased $34.5 million primarily~~23.7%, due to ~~lower natural gas prices and burn volumes for our~~unfavorable hydro conditions, driving an increase in combustion turbine generation, ~~plants.~~

which decreased the need to purchase additional wholesale power.

~~Residential exchange credits~~ decreased $42.6 million resulting from lower Residential Exchange Program (REP) credits associated with the BPA REP settlement. The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE. The program is administered by the BPA. Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

~~2015 compared to 2014~~

•Electric ~~Operating Revenue~~

~~Electric operating revenues~~generation fuel expense increased $44.7 million primarily due to higher residential sales of $57.9 million, higher commercial sales of $43.0 million, partially offset by decreased deferred decoupling revenue and other decoupling revenue of $12.1 million and $22.2 million, respectively and other electric operating revenue of $34.5 million. These items are discussed in detail below:

~~Electric retail sales~~ increased $107.9 million due to increases in rates of $113.5 million due primarily to additional $49.1 million credit provided to customers on Jefferson County Public Utility District (JPUD) gain in 2014, $17.0 million of additional Residential Exchange credits, and $12.9 million additional Renewable Energy Credit (REC) credits in 2014, which was partially offset by $5.6 million due to lower retail electricity usage.

~~Decoupling revenue~~ ~~resulted in a decrease of $12.1 million due to the allowed decoupled revenues per customer as compared to volumetric revenues in 2015 compared to 2014.~~

~~Other decoupling revenue~~ ~~decreased $22.2 million due to $12.8 million recovery from customers and $9.4 million related to over earnings sharing band of the decoupling mechanism.~~

~~Other electric operating revenue~~ ~~decreased $34.5~~$78.7 million primarily due to a ~~reduction of non-core natural gas sales of $23.8~~$63.0 million ~~and biogas revenues of $10.1 million.~~

~~Electric Power Costs~~

~~Electric power~~increase in combustion turbine generation costs ~~increased $11.6 million~~ primarily ~~due to~~driven by an increase in generation of ~~$14.6 million~~61.2% as a result of ~~purchase~~favorable heat rates, unfavorable wholesale electricity ~~costs, an increase~~prices, reduced hydro purchases of ~~$13.6 million~~23.7% and reduced hydro and wind generation of ~~electric generation fuel costs~~22.0% and 13.7%, respectively. This was partially offset by a decrease in cost per kWh generated of ~~$16.6 million~~8.7%,

For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Electric Margin" of ~~residential exchange credits. The following items are discussed in detail:~~Form 10-K for period ended December 31, 2018.

~~Purchased electricity~~ ~~expense decreased $14.6 million primarily due to a $27.4 million decrease in long-term firm and market power purchases, partially offset by $10.1 million related to the PCA customer portion in 2014.~~

~~Electric generation fuel~~ ~~expense decreased $13.6 million primarily due to lower natural gas prices for our combustion turbine generation plants.~~

~~Residential exchange credits~~ decreased $16.6 million resulting from lower REP credits associated with the BPA REP settlement. The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Natural Gas Margin

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

The following ~~table and discussion highlights significant items that impact natural gas operating revenue and natural gas energy costs which are included~~chart displays the changes in PSE’s natural gas margin for the years ended December 31, ~~2016, 2015 and 2014:~~2018, to December 31, 2019:

Natural Gas Margin
Year Ended
December 31,
Dollar Change
Year Ended
December 31,
Dollar Change
(Dollars in Thousands) 2016 2015 2014
Natural gas operating revenue:
Residential sales $ 578,955
$ 597,572
$ (18,617 ) $ 644,055
$ (46,483 )
Commercial sales 235,695
268,044
(32,349 ) 281,526
(13,482 )
Industrial sales 19,643
22,420
(2,777 ) 25,366
(2,946 )
Total retail sales 834,293
888,036
(53,743 ) 950,947
(62,911 )
Transportation sales 20,322
18,666
1,656
17,069
1,597
Decoupling revenue 52,114
51,981
133
29,116
22,865
Other decoupling revenue¹
(28,761 ) (26,038 ) (2,723 ) 2,208
(28,246 )
Other 12,542
14,904
(2,362 ) 13,520
1,384
Total natural gas operating revenues²
890,510
947,549
(57,039 ) 1,012,860
(65,311 )
Minus purchased gas costs²
(313,954 ) (403,310 ) 89,356
(458,691 ) 55,381
Natural gas margin³
$ 576,556
$ 544,239
$ 32,317
$ 554,169
$ (9,930 )

Natural Gas Volumes
(Therms in Thousands)
Residential 521,771
492,997
28,774
527,423
(34,426 )
Commercial firm 233,586
230,507
3,079
242,095
(11,588 )
Industrial firm 22,783
23,777
(994 ) 26,481
(2,704 )
Interruptible 49,533
43,931
5,602
46,113
(2,182 )
Total retail natural gas volumes, therms 827,673
791,212
36,461
842,112
(50,900 )
Transportation volumes 230,724
220,392
10,332
211,429
8,963
Total natural gas volumes 1,058,397
1,011,604
46,793
1,053,541
(41,937 )

_______________


¹	~~Includes decoupling cash collections, rate of return excess earnings, and decoupling 24-month revenue reserve.~~


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


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

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

~~2016~~2018 compared to ~~2015~~2019

Natural Gas Operating Revenue

Natural gas operating revenue~~decreased $57.0~~ increased $24.6 million primarily due to ~~lower~~higher retail sales of $9.3 million, increased transportation and other revenue of $11.9 million and increased other decoupling revenue of $7.3 million; partially offset by a decrease in decoupling revenue of $3.8 million. These items are discussed in the following details:

•Natural gas retail sales increased $9.3 million due to an increase in natural gas load of 4.8%, or $44.7 million in natural gas sales, which was partially offset by a decrease in rates of $35.4 million. Natural gas load increased primarily due to the year over year increase in usage for residential and commercial firm customers of 6.0% and 4.9%, respectively. These increases were driven by a 3.5% increase in heating degree days as well as a 1.3% increase in natural gas customers. See Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for rate changes.

•Decoupling revenue decreased $3.8 million. This is primarily attributable to higher natural gas usage, as noted above in the retail ~~sales~~ revenue section. This resulted in actual natural gas revenues being closer to allowed natural gas revenues in the current year as compared to the prior year.

•Other decoupling revenue increased $7.3 million, primarily due to a $12.0 million decrease in current year amortization of ~~$53.7~~prior year under collection, due to lower amortization rates. This was offset in part by activity related to earnings in excess of allowed ROR. In 2018, the prior year's estimate of earnings in excess of allowed ROR was trued up to match actual earnings in excess of allowed ROR by a favorable $3.4 million. In 2019, there was no prior year estimate of earnings in excess of allowed ROR to require true up. Also in 2018, earnings in excess of allowed ROR of $3.5 million was passed back to customers. In the current year, only $2.2 million was passed-back to customers.

•Transportation and other revenue increased $11.9 million primarily due to tax reform deferrals for revenue subject to refund of $15.4 million.

Natural Gas Energy Costs

Purchased natural gas expense decreased $5.7 million due to a decrease ~~of $90.6 million related to the PGA rate reduction, partially offset by an increase of $41.0 million~~ in ~~gas sales due to higher therms sold. Commercial and residential customers contributed $32.3 and $18.6 million of the net change, respectively.~~

~~Natural Gas Energy Costs~~

~~Purchased natural gas~~ ~~expense decreased $89.4 million due to lower~~ natural gas costs included in PGA rates which was partially offset by an increase in natural gas usage of ~~4.6%~~4.8%.

~~2015 compared to 2014~~

For additional information on prior years, please see discussion in Item 7, "Non-GAAP Financial Measures - Natural Gas ~~Operating Revenue~~Margin" of Form 10-K for period ended December 31, 2018.

~~Natural gas operating revenue~~ decreased $65.3 million due primarily to lower natural gas retail sales revenue of $62.9 million as a result of lower natural gas therm sales, PGA rate reduction and partially offset by decoupling revenue. These items are discussed in detail below.

~~Natural gas retail sales revenue~~ ~~decreased $62.9 million primarily due to a decrease of $57.5 million in natural gas sales due to lower therms sold and $5.4 million due to the PGA rate reduction.~~

~~Decoupling revenue~~ ~~resulted in an increase of $22.9 million due to lower volumetric revenues compared to the allowed decoupled revenues per customer.~~

~~Other Decoupling revenue~~ decreased $28.2 million due to return of over earnings sharing band of the decoupling mechanism of $10.5 million, 24-month exceeding the collection period for decoupling of $10.0 million and collection from customers of $7.8 million.

~~Natural Gas Energy Costs~~

~~Purchased natural gas~~ ~~expense decreased $55.4 million due to lower natural gas costs reflected in PGA rates and by a decrease in usage of 6.0%.~~

Other Operating Expenses and Other Income (Deductions)

The following ~~table~~chart displays the details of PSE's other operating expenses and other income (deductions) ~~from periods 2016~~for the years ended December 31, 2018, to ~~2015 and periods 2015 to 2014:~~December 31, 2019:

Puget Sound Energy
Year Ended
December 31,
Dollar Change
Year Ended
December 31,
Dollar Change
(Dollars in Thousands) 2016 2015 2014
Operating expenses:

Net unrealized (gain) loss on derivative instruments $ (83,795 ) $ (12,688 ) $ (71,107 ) $ 85,636
$ (98,324 )
Utility operations and maintenance 568,492
530,720
37,772
550,146
(19,426 )
Non-utility expense and other 37,859
26,618
11,241
23,729
2,889
Depreciation and amortization 439,579
420,807
18,772
365,606
55,201
Conservation amortization 107,784
110,866
(3,082 ) 104,096
6,770
Taxes other than income taxes 328,649
320,531
8,118
310,982
9,549
Other income (deductions):
Other income 25,537
20,711
4,826
24,036
(3,325 )
Other expense (10,923 ) (6,764 ) (4,159 ) (7,457 ) 693
Interest expense, net of AFUDC (233,679 ) (239,996 ) 6,317
(259,316 ) 19,320
Income tax expense 175,347
125,900
49,447
89,342
36,558

~~2016~~2018 compared to ~~2015~~2019

Other Operating Expenses

•Net unrealized (gain) loss on derivative instruments ~~increased $71.1~~ decreased $45.2 million to a ~~gain~~net loss of ~~$83.8 million. The net gain in 2016 was comprised~~$3.6 million for the year ended December 31, 2019. One of ~~a gain of $62.3 million~~the drivers for the change is related to the net settlements of electric and natural gas trades previously recorded as $36.4 million in gains and $15.4 million in losses, respectively. The other driver is related to the change in the weighted average forward prices for ~~power~~electric and natural gas. Specifically, electric price decreased 16.7% resulting in a $2.6 million loss for electric. Natural gas derivative ~~instruments~~unrealized losses of $21.6 million were due to a higher cost basis of forward trades due to high natural gas prices in late 2018 and early 2019 and a ~~$21.5~~decrease in forward prices at December 31, 2019.

•Utility operations and maintenance expense decreased $6.0 million gain related to electricity derivative instruments. This compares to a gain of $22.0 million related to electricity derivative instruments and a loss of $9.3 million related to natural gas for power derivative instruments, respectively, during the prior year. The gain was primarily due to ~~increases~~a decrease in ~~natural gas~~the following: (i) bad debt expense of $5.4 million due to an improved collection process, (ii) underground cable maintenance expense of $2.5 million, (iii) leak surveys expense of $2.3 million due to reliability strategic initiatives, and ~~wholesale electricity forward prices.~~

~~Utility operations and maintenance~~(iv) rent expense ~~increased $37.8~~of $1.7 million ~~primarily driven~~due to facility consolidations; partially offset by ~~(i)~~(v) an increase in hardware and software maintenance costs of ~~$15.7~~$7.5 million ~~of administrative and general expense, primarily~~ due to an increase in ~~outside services employed~~IT projects..

•Non-utility and other expense decreased $7.0 million primarily due to a decrease in biogas gas purchase expense of ~~$7.4~~$5.6 million and a decrease in non-qualified pension plan costs of $1.9 million; partially offset by an increase in the long-term incentive plan accrual of ~~electric maintenance expense of $3.2~~$1.4 million ~~and an increase of administrative and general salary expense of $2.9 million; (ii) $10.7 million of natural gas operation expense primarily~~ due to an increase in ~~distribution operation~~long-term incentive plan awards in 2019.

•Depreciation and ~~maintenance~~amortization expense decreased $25.2 million primarily driven by: (i) a decrease in amortization of PTC regulatory liability of $15.4 million in 2019 as compared to 2018, (ii) a decrease of $21.7 million in common amortization due the deferral treatment of IT amortization effective May 1, 2019, as submitted to the Washington Commission, (iii) a decrease of $11.0 million for ~~mains and services~~amortization of ~~$6.2~~the Microsoft transition fee set in rates by a Washington Commission order, (iv) a decrease in amortization driven by the deferral treatment of $12.7 million for meter assets effective April 1, 2019, as submitted to ~~increase system reliability; (iii) $7.6~~the Washington Commission, (v) a decrease in conservation

amortization of $15.1 million ~~of operations and maintenance expense at our generation plants and (iv) $5.4 million of electric distribution maintenance overhead line expense;~~due to lower rates in 2019 as compared to 2018; partially offset by ~~(v) $4.6~~(vi) an increase in common amortization of $33.8 million ~~in meter reading expense.~~

~~Depreciation and amortization~~driven by net additions of $88.3 million of software; (vii) electric depreciation expense increased ~~$18.8~~$10.2 million primarily due to ~~$16.5~~net asset additions to distribution of $212.5 million ofand (viii) an increase in natural gas depreciation expense of $7.3 million primarily due to net asset additions to distribution of ~~$173.9 million of natural gas distribution assets, $148.5 million of electric distribution assets and $90.6 million of electric transmission assets.~~

$214.5 million.

•Taxes other than income taxes ~~increased $8.1~~ decreased $2.7 million primarily due to ~~an increase~~decreases in ~~electric property taxes of $6.0 million from an increase in load, electric state excise taxes of $2.9 million and~~ municipal taxes of ~~$2.9~~$2.4 million ~~due to increased revenue, partially offset by~~, as well as a decrease of ~~$2.7 million in natural gas municipal taxes and~~ $2.1 million ~~in natural gas state excise taxes due~~related to ~~decreased revenue.~~

the property tax tracker.

Other Income, Interest Expense and Income Tax Expense

~~Interest~~ •Other income/expense decreased ~~$6.3~~$10.1 million ~~primarily due to~~as a result of an increase in other income of $7.9 million and a decrease in other expenses of ~~$3.8~~$2.1 million. Primarily contributing to the increase was an increase of $6.6 million of PGA interest income. Additionally, there was an increase in ~~interest on long-term debt and $1.7 million related to~~Washington Commission allowance for funds used during construction (AFUDC) ~~debt.~~

of $3.9 million due to a $31.8 million increase in eligible construction work in progress in 2019 as compared to 2018.

~~Income tax~~•Interest expense increased ~~$49.4~~$11.3 million primarily ~~driven by a higher pre-tax income and a decrease in PTCs generated.~~related to PSE's issuance of $450.0 million of senior notes at an interest rate of 3.25%. For additional information, see Note ~~13,~~7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.

•Income tax expense decreased $11.6 million primarily driven by $7.5 million attributable to a decrease in pre-tax income and $4.0 million to attributable to permanent and flow through items. For further details, see Note 14, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.

~~2015 compared to 2014~~

~~Other~~For additional information on prior years, please see discussion in Item 7, "Other Operating Expenses

~~Net unrealized (gain) loss on derivative instruments~~ ~~increased $98.3 million to a gain of $12.7 million. The net gain in 2015 was comprised of a gain of $22.3 million related to electricity derivative instruments~~ and a $9.3 million loss related to PSE's natural gas derivative instruments for power. This compares to a loss of $42.3 million related to PSE's natural gas for power derivative instruments and a loss of $43.3 million related to electricity derivative instruments, respectively, during the prior year. The gain was primarily due to decreases in natural gas and wholesale electricity forward prices.

~~Utility operations and maintenance~~ ~~expense decreased $19.4 million primarily driven by a decrease of $8.3 million in bad debts expense and $7.0 million in meter reading expenses.~~

~~Depreciation and amortization~~ expense increased $55.2 million primarily due to $43.6 million of electric amortization expense from $46.9 million of regulatory credits related to the JPUD gain on sale returned to customers and a net increase of $3.1 million of Electron sale loss amortization, partially offset by a decrease of $5.7 million in PTC deferral. Natural gas depreciation also increased in the amount of $5.3 million, mainly due to new additions.

~~Conservation amortization~~ ~~increased $6.8 million primarily due to an increase of $6.2 million in conservation rider rate annual adjustments.~~

~~Taxes other than income taxes~~ ~~increased $9.5 million primarily due to an increase in property taxes of $5.7 million, state excise taxes of $4.3 million and municipal taxes of $2.4 million.~~

Other Income ~~Interest Expense and Income Tax Expense~~(Deductions)" of Form 10-K for period ended December 31, 2018.

~~Other income~~ decreased $3.3 million primarily due to PSE's share of the JPUD gain of $7.5 million in 2014, which was partially offset by an increase in AFUDC equity income of $2.3 million and an increase in interest and dividend income of $1.4 million.

~~Interest expense~~ decreased $19.3 million primarily due to a decrease of $12.0 million in regulatory liability interest expense, a reduction of $3.5 million of interest on long term debt, and an increase of $2.0 million of AFUDC debt.

~~Income tax expense~~ ~~increased $36.6 million primarily driven by a higher pre-tax income.~~

Puget Energy

Substantially all the operations of Puget Energy are conducted through its regulated subsidiary, PSE. Puget Energy’s ~~net income~~results of operation for the years ended December 31, ~~2016, 2015~~2018, and ~~2014 was~~December 31, 2019, were as follows:

Benefit/(Expense)
Year Ended
December 31,
Dollar Change Year Ended
December 31, Dollar Change
(Dollars in Thousands) 2016 2015 2014
PSE net income $ 380,581
$ 304,189
$ 76,392
$ 236,614
$ 67,575
Other operating revenue and income (316 ) (558 ) 242
(2,949 ) 2,391
Net unrealized gain on derivative instruments —
544
(544 ) 1,491
(947 )
Non-utility expense and other 10,710
15,801
(5,091 ) 10,620
5,181
Non-hedged interest rate swap expense (1,062 ) (3,796 ) 2,734
(3,915 ) 119
Interest expense ¹
(112,156 ) (109,125 ) (3,031 ) (102,382 ) (6,743 )
Income tax benefit (expense) 35,142
34,124
1,018
32,356
1,768
Puget Energy net income $ 312,899
$ 241,179
$ 71,720
$ 171,835
$ 69,344

~~_______________~~


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

~~2016~~2018 compared to ~~2015~~2019

Summary Results of Operations

Puget Energy’s net income ~~increased~~decreased by ~~$71.7~~$24.9 million, which is primarily attributable to a decrease in PSE's net income ~~increase~~ of ~~$76.4~~$24.2 million. ~~The following are significant factors that impacted Puget Energy’s net income which are not included~~

For additional information on prior years, please see discussion in ~~PSE’s discussion:~~

~~Non-utility expense and other~~ ~~decreased $5.1 million primarily due to legal outside services of $2.8 million, qualified pension expense of $1.2 million.~~

~~2015 compared to 2014~~

Item 7, "PE Summary Results of ~~Operations~~Operation" of Form 10-K for period ended December 31, 2018.

Puget Energy’s net income increased by $69.3 million, which is primarily attributable to PSE's net income increase of $67.6 million. The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:

~~Non-utility expense and other~~ ~~increased $5.2 million primarily due to higher pension expense related to the qualified pension plan.~~

~~Interest expense~~ ~~increased $6.7 million primarily due to interest expense on the long-term senior secured notes issued in 2015.~~

Capital Resources and Liquidity

Capital Requirements

Contractual Obligations and Commercial Commitments

The following are PSE’s and Puget Energy’s aggregate contractual obligations as of December 31, ~~2016:~~2019:


	Payments Due Per Period
(Dollars in Thousands)	Total		2020		2021-2022		2023-2024		Thereafter
Contractual obligations:
Energy purchase obligations¹	$	6,355,478	$	1,033,400	$	1,574,582	$	1,339,851	$	2,407,645
Long-term debt including interest²	8,874,206		229,109		453,394		453,394		7,738,309
Short-term debt including interest	176,000		176,000		—		—		—
Service contract obligations	615,117		72,445		149,517		155,189		237,966
Non-cancelable operating leases³	269,398		22,500		44,383		42,105		160,410
PSE finance leases³	1,528		643		787		98		—
Pension and other benefits funding and payments	82,967		41,659		8,316		10,495		22,497
Total PSE contractual cash obligations	16,374,694		1,575,756		2,230,979		2,001,132		10,566,827
Long-term debt including interest²	2,428,548		547,880		1,422,008		53,300		405,360
Total Puget Energy contractual cash obligations	$	18,803,242	$	2,123,636	$	3,652,987	$	2,054,432	$	10,972,187

Payments Due Per Period
(Dollars in Thousands) Total 2017 2018 - 2019 2020 - 2021 Thereafter
Contractual obligations:
Energy purchase obligations¹
$ 6,147,014
$ 1,041,888
$ 1,532,971
$ 1,227,542
$ 2,344,613
Long-term debt including interest²
8,561,749
220,061
614,432
408,338
7,318,918
Short-term debt including interest 245,775
245,775
—
—
—
Service contract obligations 596,660
49,748
100,694
124,720
321,498
Non-cancelable operating leases³
187,161
22,212
37,912
24,644
102,393
PSE capital leases³
666
296
370
—
—
Pension and other benefits funding and payments 71,401
20,236
10,944
6,178
34,043
Total PSE contractual cash obligations 15,810,426
1,600,216
2,297,323
1,791,422
10,121,465
Long-term debt including interest²
2,330,495
99,242
210,805
1,107,765
912,683
Total Puget Energy contractual cash obligations $ 18,140,921
$ 1,699,458
$ 2,508,128
$ 2,899,187
$ 11,034,148

~~_______________~~


^{1^{____________________}}	Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.


²	For individual long-term debt maturities, see Note 6, "Long-Term Debt," to the consolidated financial statements included in Item 8 of this report. For Puget Energy, the amount above excludes the fair value adjustments related to the merger.


³	~~For additional information, see Note 8, "Leases," to the consolidated financial statements included in Item 8 of this report.~~

^1.Energy purchase contracts were entered into as part of PSE’s obligation to serve retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.

^2.For individual long-term debt maturities, see Note 7, "Long-Term Debt," to the consolidated financial statements included in Item 8 of this report. For Puget Energy, the amount above excludes the fair value adjustments related to the merger.

^3.For additional information, see Note 9, "Leases" to the consolidated financial statements included in Item 8 of this report.

The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of December 31, ~~2016~~:2019:


	Amount of Available Commitments Expiration Per Period													Amount of Available Commitments Expiration Per Period
(Dollars in Thousands)	Total			2017		2018 - 2019		2020 - 2021		Thereafter			(Dollars in Thousands)	Total	2020	2021-2022	2022-2023	Thereafter
Commercial commitments:													Commercial commitments:
PSE working capital facility¹	$	650,000		$	—	$	650,000	$	—	$	—
PSE energy hedging facility¹	350,000			—		350,000		—		—
PSE revolving credit facility¹													PSE revolving credit facility¹	$800,000	$—	$—	$800,000	$—
Inter-company short-term debt²	30,000			—		—		—		30,000			Inter-company short-term debt²	30,000	—	—	—	30,000
Total PSE commercial commitments	1,030,000			—		1,000,000		—		30,000			Total PSE commercial commitments	830,000	—	—	800,000	30,000
Puget Energy revolving credit facility³	800,000			—		800,000		—		—			Puget Energy revolving credit facility³	775,900	—	—	775,900	—
Less: Inter-company short-term debt elimination²	(30,000		)	—		—		—		(30,000		)	Less: Inter-company short-term debt elimination²	(30,000)	—	—	—	(30,000)
Total Puget Energy commercial commitments	$	1,800,000		$	—	$	1,800,000	$	—	$	—		Total Puget Energy commercial commitments	$1,575,900	$—	$—	$1,575,900	$—

_______________

As of December 31, 2016, PSE had two credit facilities which provide, in the aggregate, $1.0 billion of short-term liquidity needs, and which will mature in April 2019. These facilities consisted of a $650.0 million revolving liquidity facility to be used for general corporate purposes, including a backstop to the Company's commercial paper program, and a $350.0 million energy hedging 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 that, upon the banks' approval, would increase the total size of these facilities to $1.5 billion. As of December 31, 2016, no loans or letters of credit were outstanding under the PSE energy hedging facility, no loans or letters of credit were outstanding under the PSE liquidity facility and $245.8 million was outstanding under the commercial paper program. The credit agreements are syndicated among numerous lenders. Outside of the credit agreements, PSE has a $3.5 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.


²	~~As of~~ ~~December 31, 2016, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.~~

~~As of~~ ~~December 31, 2016~~, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in April 2018. The revolving senior secured credit facility is syndicated among numerous lenders. The revolving senior secured credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of December 31, 2016, there was $12.5 million drawn and outstanding under the Puget Energy credit facility.

^1.As of December 31, 2019, PSE had a credit facility which provides $800.0 million of short-term liquidity needs and includes a backstop to the Company's commercial paper program. The credit facility matures in October 2023. The credit facility also includes a swingline feature allowing same day availability on borrowings up to $75.0 million and an expansion feature that, upon the banks' approval, would increase the total size of the facility to $1.4 billion. As of December 31, 2019, no loans or letters of credit were outstanding under the credit facility and $176.0 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $2.8 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.

^2.As of December 31, 2019, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million.

^3.As of December 31, 2019, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2023. The revolving senior secured credit facility is syndicated among numerous lenders. The revolving senior secured credit facility also has an expansion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. As of December 31, 2019, there was $24.1 million drawn and outstanding under the Puget Energy credit facility.

Off-Balance Sheet Arrangements

As of December 31, ~~2016,~~2019, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program

PSE’s construction programs for generating facilities, the electric transmission system, the natural gas and electric distribution systems and the Tacoma LNG facility are designed to meet regulatory requirements and customer growth and to support reliable energy delivery. Construction expenditures, excluding equity AFUDC, totaled ~~$681.1~~$919.3 million in ~~2016.~~2019. Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:


Capital Expenditure Projections
(Dollars in Millions)	2020	2021	2022
Total energy delivery, technology and facilities expenditures	$965.5	$1,031.1	$1,023.7

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

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

Capital Resources

Cash from Operations


Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2019		2018		Change
Net income	$	292,924	$	317,162	$	(24,238)
Non-cash items¹	677,261		670,632		6,629
Changes in cash flow resulting from working capital²	(107,355)		80,541		(187,896)
Regulatory assets and liabilities	(79,173)		(71,348)		(7,825)
Purchased gas adjustment	(132,766)		—		(132,766)
Other non-current assets and liabilities³	(26,967)		(1,083)		(25,884)
Net cash provided by operating activities	$	623,924	$	995,904	$	(371,980)

~~2016~~_______________

^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.

Year Ended December 31, 2019, compared to ~~2015~~2018

~~Puget Sound Energy~~

Cash generated from operations for the year ended December 31, ~~2016 increased~~2019, decreased by ~~$80.1~~$372.0 million, including ~~$76.4 million from~~a net ~~income.~~income decrease of $24.2 million. The following are significant factors that impacted PSE's cash flows from operations:

~~The increase in cash~~•Cash flow adjustments resulting from ~~accounts receivable and unbilled revenue was the result~~non-cash items increased $6.6 million primarily due to a $45.2 million change from a net unrealized gain on derivative instruments of $41.7 million to a net unrealized loss on derivative instruments of $3.6 million, as well as a decrease ~~of $29.2 million from $66.5 million~~ in 2015 to $37.4 million in 2016. The reduction in accounts receivable resulted from implementation of an improved collections strategy in 2016. Unbilled revenue primarily decreased due to an increase in load; allowing for billing of prior year accrued revenue.

~~The increase in cash flow from deferred income taxes and~~production tax credits monetization of ~~$48.9~~$15.4 million, offset by decreases in depreciation and amortization of $10.1 million, conservation amortization of $15.1 million, amortization of TCJA related income tax expense over-collection of $19.7 million and deferred taxes of $10.5 million. For further discussion, see "Other Operating Expenses" in Item 7, Management's Discussion and Analysis and Note 14, "Income Taxes" in Item 8.

•Cash flows resulting from ~~$125.9~~changes in working capital decreased $187.9 million ~~in 2015 to $174.8 million in 2016 was~~ primarily due to increased ~~additions~~cash outflow in accounts payable by $233.8 million, which was mainly due to ~~plant~~payment of significant power and natural gas costs accrued as of December 31, 2018, that were paid in ~~2016.~~2019. In addition, cash outflows associated with taxes payable increased by $18.9 million. These increased cash outflows are partially offset by increased cash inflows as

~~The~~

results of decreased balance in short-term purchased gas adjustment receivables of $35.9 million and accrued expenses of $23.5 million.

•Cash flows resulting from regulatory assets and liabilities decreased $7.8 million primarily caused by an increase in the PCA mechanism due to actual power costs being above power baseline costs. For further details, see "Electric Margin" in Item 7, Management's Discussion and Analysis.

•Cash flow resulting from purchased gas adjustment (long-term) decreased $132.8 million caused by actual natural gas costs being above natural gas baseline rates in the PGA mechanism. For further details, see "Natural Gas Margin" in Item 7, Management's Discussion and Analysis.

•Cash flow resulting from changes in other non-current assets and liabilities decreased $25.9 million primarily due to an decrease in ~~cash flow from~~pension liability offset with other changes in long-term assets and liabilities.


Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2019		2018		Change
Net income	$	(82,216)	$	(81,540)	$	(676)
Non-cash items¹	(2,381)		(519)		(1,862)
Changes in cash flow resulting from working capital²	(4,800)		4,558		(9,358)
Regulatory assets and liabilities	(60)		—		(60)
Other non-current assets and liabilities³	(7,131)		(14,222)		7,091
Net cash provided by operating activities	$	(96,588)	$	(91,723)	$	(4,865)

______________

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

^3.Other non-current assets and liabilities include funding of ~~an increase in net unrealized gain of $71.1 million from $12.7 million in 2015~~pension liability.

Year Ended December 31, 2019, compared to $83.8 million in 2016. The net gain in 2016 was comprised of a gain of $62.3 million related to natural gas for power derivative instruments and a $21.5 million gain related to electricity derivative instruments. This compares to a gain of $22.0 million related to electricity derivative instruments and a loss of $9.3 million related to natural gas for power derivative instruments, respectively, during the prior year. The gain was primarily due to increases in natural gas and wholesale electricity forward prices.2018

~~Puget Energy~~

Cash generated from operations for the year ended December 31, ~~2016 increased~~2019, decreased by ~~$80.1~~$4.9 million compared to the same period in ~~2015.~~2018. The net difference was ~~primarily~~ impacted by the ~~increase~~decrease from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below:

•Non-cash items decreased $1.9 million primarily due to changes in deferred taxes of $1.5 million.

•Changes in cash flow resulting from working capital decreased $9.4 million primarily due to amounts owed to PSE related to Puget LNG and that are eliminated at consolidated PE.

•Other non-current assets and liabilities increased $7.1 million primarily due to change of the valuation of pension liability compared to the prior year.

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, 2016 and 2015, PSE had $245.8 million and $159.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt,~~For information on Puget Energy ~~had no short-term~~and PSE dividends, long-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 5, “Dividend Payment Restrictions, Note 7, “Long-term Debt” and ~~the amortization of debt issuance costs, during 2016~~Note 8, “Liquidity Facilities and ~~2015 was 3.21%, and 4.24%, respectively. As of December 31, 2016, PSE and Puget Energy had several committed credit facilities that are described below.~~

~~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 backstopOther Financing Arrangements” to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.5 billion. These unsecured revolving credit facilities matureconsolidated financial statements included 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, 2016, 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 dateItem 8 of this ~~report, the spread to the LIBOR is 1.75% and the commitment fee is 0.275%.~~report.

As of December 31, 2016, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $245.8 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.5 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

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, ~~2016,~~2019, PSE could issue:

•Approximately ~~$2.5~~$2.0 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately ~~$4.1~~$3.3 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at December 31, ~~2016;~~2019; and

•Approximately ~~$485.0~~$739.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately ~~$808.3 million~~$1.2 billion of natural gas bondable property available for issuance, subject to a combined natural gas

and electric interest coverage test of 1.75 times net earnings available for interest and a natural gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at December 31, ~~2016.~~

2019

At December 31, ~~2016,~~2019, PSE had approximately ~~$6.9~~$7.8 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~~

On November 21, 2016, PSE filed a shelf registration statement under which it may issue, as of the date of this report, up to $800.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The shelf registration will expire in November 2019.

On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. 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, 2016, approximately $532.9 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 1.0. The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 and the EBITDA to interest expense was 5.2 to 1.0 for the 12 months ended December 31, 2016.

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, 2016, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures in 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, 2016, there was $12.5 million drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275% 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. For additional information, see Part II Item 7A, "Interest Rate Risk".

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, 2016, Puget Energy was in compliance with all applicable covenants.

~~Long-Term Debt Activity~~

In May 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes 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 outstanding Puget Energy indebtedness and to fund a special dividend to shareholders. In November 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 1.0. Puget Energy's EBITDA to interest expense was 3.5 to 1.0 for the 12 months ended December 31, 2016.

~~At December 31, 2016, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.~~

Other

Critical Accounting Policies 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

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~~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 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, for GAAP purposes only, the~~The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of 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 will be recorded.

For further discussion regarding revenue recognition, see Note 3, "Revenue", to the consolidated financial statements included in Item 8 of this report.

Regulatory 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, ~~2016~~2019, in the amount of ~~$1,113.2~~$847.5 million and ~~$653.3~~$1,676.6 million, respectively, and regulatory assets and liabilities at December 31, ~~2015~~2018, of ~~$971.5~~$788.2 million and ~~$663.7~~$1,722.5 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 ~~Item 1, "Business – Regulation~~Management's Discussion and Analysis, "Regulation and Rates". included in Item 7 of this report. 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~~

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 first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential 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, 2016. 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: (i) estimation of future cash flows, which is dependent on internal forecasts, (ii) estimation of the long-term rate of growth for Puget Energy’s business, (iii) estimation of the useful life over which cash flows will occur, (iv) the selection of utility holding companies determined to be comparable to Puget Energy, and (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 $5.2 billion at the October 1, 2016 measurement date for the annual test of goodwill impairment. The carrying value of Puget Energy’s equity was approximately $3.6 billion with the excess of the fair value over the carrying value representing 43.0% or $1.6 billion.

The income approach and the market approach valuations each resulted in Puget Energy equity values of $5.2 billion. 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 2.6% and 5.7%, respectively.

~~The following table summarizes the results of the income valuation 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
2.4 % 2.5 % 2.6 % 2.7 % 2.8 % 2.9 %
5.9% $ 3.5
$ 3.8
$ 4.1
$ 4.5
$ 4.8
$ 5.2
5.7 4.4
4.8
5.2
5.6
6.0
6.4
5.4 5.5
5.9
6.4
6.8
7.3
7.9

Derivatives

ASC 815 ~~“Derivatives and Hedging” (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. The Company 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 (NPNS) exception to derivative accounting rules. Generally, NPNS applies to contracts with creditworthy counterparties, for which physical delivery

is probable and in quantities that will be used in the normal course of business. Power purchases designated as NPNS must meet additional criteria to determine if the transaction is within PSE’s forecasted load requirements and if the counterparty owns or controls energy resources within the western region to allow for physical delivery of the energy. PSE may enter into financial fixed 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. Natural gas derivative contracts qualify for deferral under ASC 980 due to the 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 their financial 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 contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (OCI) 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.

PSE values derivative instruments based on daily quoted prices from an independent external pricing service. The Company regularly confirms the validity of pricing service quoted prices (e.g. Level 2 in the fair value hierarchy) used to value commodity contracts to the actual prices of commodity contracts entered into during the most recent quarter. When external quoted market prices are not available for derivative contracts, PSE 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. The Company is focused on commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. ItPSE is not engaged in the business of assuming risk for the purpose of speculative trading. The Company economically hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices. The exposure position is determined by using a probabilistic risk system that models 250 simulations of how the Company’s natural gas and power portfolios will perform under various weather, hydrological and unit performance conditions.

~~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, 2016, Puget Energy had interest rate swap contracts outstanding originally related to its long-term debt.~~ For additional information, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" ~~and~~ Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" and Note 10,11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

Fair Value

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). However, 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 this 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. For further discussion on market risk, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk".

Pension and Other Postretirement Benefits

PSE has a qualified defined benefit pension plan covering substantially all employees of PSE. PSE recognized qualified pension expense of ~~$14.5 million, $22.9~~$12.6 million and ~~$13.8~~$13.2 million for the years ended December 31, ~~2016, 2015~~2019, and ~~2014,~~2018, respectively. Of these amounts, approximately ~~55.5%, 58.5%~~49.0% and ~~61.5%~~49.4% were included in utility operations and maintenance expense in ~~2016, 2015~~2019 and ~~2014,~~2018, respectively, and the remaining amounts were capitalized. For the years ended December 31, ~~2016~~2019, and ~~2015,~~2018, Puget Energy recognized incremental qualified pension income of ~~$15.5~~$12.1 million and ~~$16.7~~$13.1 million, respectively. In ~~2017,~~2020, it is expected that PSE and Puget Energy will recognize pension expense of ~~$12.7~~$16.2 million and incremental qualified pension income of ~~$14.0~~$11.1 million, respectively.

PSE has a Supplemental Executive Retirement Plan (SERP). PSE recognized pension and other postretirement benefit expenses of ~~$4.8 million, $5.6~~$5.4 million and ~~$4.9~~$5.1 million for the years ended December 31, ~~2016, 2015~~2019, and ~~2014,~~2018, respectively. For the years ended December 31, ~~2016~~2019, and ~~2015,~~2018, Puget Energy recognized incremental income of $0.4 million and $0.5 million, respectively. In ~~2017,~~2020, it is expected that PSE and Puget Energy will recognize pension expense of ~~$4.8~~$5.4 million and incremental pension income of ~~$0.5~~$0.3 million, respectively.

PSE also has other limited postretirement benefit plans. PSE recognized income of $0.5 million ~~$0.2 million~~ and ~~$0.4~~$0.5 million for the years ended December 31, ~~2016, 2015~~2019, and ~~2014,~~2018, respectively. For the years ended December 31, ~~2016~~2019, and ~~2015,~~2018, Puget Energy recognized incremental expense of $0.2 million each year. In ~~2017,~~2020, it is expected that PSE and Puget Energy will recognize ~~income~~expense of ~~$0.6~~$0.1 million and incremental expense of ~~$0.2~~$0.1 million, respectively.

The Company’s pension and other postretirement benefits income or expense depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care cost trends. Changes in any of these factors or assumptions will affect the amount of income or expense that the Company records in its financial statements in future years and its projected benefit obligation. The Company has selected an expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The Company’s accounting policy for calculating the market-related value of assets is based on a five-year smoothing of asset gains or losses measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. During ~~2016,~~2019, the Company made cash contributions of ~~$24.0~~$18.0 million to the qualified defined ~~benefit~~pension plan. Management is closely monitoring the funding status of its qualified pension ~~plan given the recent volatility of the financial markets.~~plan. At December 31, ~~2016~~2019, and ~~2015,~~2018, the Company’s qualified pension plan was ~~$32.3~~$21.3 million underfunded and ~~$44.2~~$37.4 million underfunded as measured under GAAP, or ~~95.0%~~97.3% and ~~93.1%~~94.5% funded, respectively. As of January 1, ~~2017,~~2020, the plan's estimated funded ratio, as calculated under guidelines from The Pension Protection Act of 2006 and considering temporary interest rate relief measures approved by Congress, was more than 100%. The aggregate expected contributions and payments by the Company to fund the pension plan, SERP and other postretirement plans for the year ending December 31, ~~2017~~2020, are expected to be at least $18.0 million, ~~$1.9~~$22.6 million and ~~$0.3~~$0.1 million, respectively.

The discount rate used in accounting for pension and other benefit obligations decreased from ~~4.65%~~4.40% in ~~2015~~2018 to ~~4.50%~~3.35% in ~~2016.~~2019. The discount rate used in accounting for pension and other benefit expense ~~increased from 4.25%~~was 4.40% in ~~2015 to 4.65% in 2016.~~both 2018 and 2019. The rate of return on plan assets for qualified pension benefits decreased was 7.50% in ~~2016 remained unchanged at the 2015 level, or 7.75%.~~both 2018 and 2019. The rate of return on plan assets for other benefits was 7.0% in ~~2016~~both 2018 and ~~2015 was 6.75% and 7.00%, respectively.~~2019.

The following tables reflect the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of other assumption changes):


Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)									Puget Energy and Puget Sound Energy	Change in Assumption	Impact on Projected Benefit Obligation Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits			(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(35,198	)	$	(1,959	)	$	(535	)	Increase in discount rate	50 basis points	$	(44,028)	$	(1,440)	$	(528)
Decrease in discount rate	50 basis points	38,965			2,091			584			Decrease in discount rate	50 basis points	48,863		1,536		576


Puget Energy	Change in Assumption	Impact on 2019 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits				SERP			Other Benefits
Increase in discount rate	50 basis points	$	(3,170)	$	(126)		$	7
Decrease in discount rate	50 basis points	3,479		137			(24)
Increase in return on plan assets	50 basis points	$	(3,498)	*			$	(28)
Decrease in return on plan assets	50 basis points	3,498		*			28

Puget Energy Change in Assumption
Impact on 2016
Pension Expense
Increase /(Decrease)
(Dollars in Thousands) Pension Benefits SERP Other Benefits
Increase in discount rate 50 basis points $ 221
$ (139 ) $ (51 )
Decrease in discount rate 50 basis points 2,562
144
51
Increase in return on plan assets 50 basis points (3,008 ) *
(33 )
Decrease in return on plan assets 50 basis points 3,008
*
33


Puget Sound Energy	Change in Assumption	Impact on 2016 Pension Expense Increase /(Decrease)									Puget Sound Energy	Change in Assumption	Impact on 2019 Pension Expense Increase /(Decrease)
(Dollars in Thousands)		Pension Benefits			SERP			Other Benefits			(Dollars in Thousands)		Pension Benefits		SERP		Other Benefits
Increase in discount rate	50 basis points	$	(2,732	)	$	(139	)	$	(50	)	Increase in discount rate	50 basis points	$	(3,717)	$	(128)	$	8
Decrease in discount rate	50 basis points	2,954			144			52			Decrease in discount rate	50 basis points	3,478		138		(7)
Increase in return on plan assets	50 basis points	(3,020		)	*			(33		)	Increase in return on plan assets	50 basis points	$	(3,499)	*		$	(28)
Decrease in return on plan assets	50 basis points	3,020			*			33			Decrease in return on plan assets	50 basis points	3,499		*		28

_______________


^*	* Calculation not applicable.

Recently Adopted Accounting Pronouncements

For the discussion of recently adopted accounting pronouncements, see Note 2,, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Energy Portfolio Management

PSE maintains energy risk policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity. PSE’s Energy Management Committee establishes PSE’s risk management policies and procedures and monitors compliance. The Energy Management Committee is comprised of certain PSE officers and is overseen by the PSE Board of Directors.

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

PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools including a probabilistic risk system that models 250 simulations of how PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions. Based on the analytics from all of its models and tools, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options to manage its electric and natural gas portfolio risks. The forward physical electric and natural gas contracts are both fixed and variable (at index). To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price ~~fluctuations.~~fluctuations while also allowing for participation in low price commodity markets.

The following table presents the fair value of the Company’s energy derivatives instruments, recorded on the balance sheets:


Puget Energy and Puget Sound Energy	December 31, 2019						December 31, 2018
(Dollars in Thousands)	Assets		Liabilities		Assets		Liabilities
Electric portfolio:
Current	$	15,399	$	9,273	$	32,041	$	22,804
Long-term	4,534		8,231		1,246		4,480
Total Electric Portfolio	19,933		17,504		33,287		27,284
Natural gas portfolio:
Current	$	8,227	$	4,155	$	14,466	$	23,857
Long-term	3,148		4,462		1,266		6,615
Total Natural Gas Portfolio	11,375		8,617		15,732		30,472
Total derivatives	$	31,308	$	26,121	$	49,019	$	57,756

Puget Energy and
Puget Sound Energy
December 31, 2016 December 31, 2015
(Dollars in Thousands) Assets Liabilities Assets Liabilities
Electric portfolio:
Current $ 30,596
$ 30,997
$ 19,051
$ 81,453
Long-term 5,864
10,332
4,392
30,653
Total electric derivatives 36,460
41,329
23,443
112,106
Natural Gas portfolio:

Current 23,745
13,172
5,367
49,967
Long-term 2,874
5,929
833
17,123
Total natural gas derivatives 26,619
19,101
6,200
67,090
Total energy derivatives $ 63,079
$ 60,430
$ 29,643
$ 179,196

At December 31, ~~2016,~~2019, the Company had total assets of ~~$63.1~~$31.3 million and total liabilities of ~~$60.4~~$26.1 million related to derivative contracts used to hedge the supply and cost of electricity and natural gas to serve PSE customers. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism. Any fair value adjustments relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism, which passes the cost of natural gas supply to customers. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism.

A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company’s derivative contracts by ~~$20.6~~$30.1 million.

The change in fair value of the Company’s outstanding energy derivative instruments from December 31, ~~2015~~2018, through December 31, ~~2016~~2019, is summarized in the table below:


Puget Energy and Puget Sound Energy
Energy Derivative Contracts Gain (Loss)
(Dollars in Thousands)	December 31, 2019
Fair value of contracts outstanding at December 31, 2018	$	(8,737)
Contracts realized or otherwise settled during 2019	(67,161)
Change in fair value of derivatives	81,084
Fair value of contracts outstanding at December 31, 2019	$	5,186

Puget Energy and
Puget Sound Energy
Energy Derivative Contracts Asset (Liability)

(Dollars in Thousands)
Fair value of contracts outstanding at December 31, 2015 $ (149,553 )
Contracts realized or otherwise settled during 2016 113,284
Change in fair value of derivatives 38,918
Fair value of contracts outstanding at December 31, 2016 $ 2,649

The fair value of the Company’s outstanding derivative instruments at December 31, ~~2016,~~2019, based on pricing source and the period during which the instrument will mature, is summarized below:


Puget Energy and Puget Sound Energy Source of Fair Value													Puget Energy and Puget Sound Energy Source of Fair Value	Fair Value of Contracts by Settlement Year
	Fair Value of Contracts by Settlement Year
(Dollars in Thousands)	2017		2018-2019			2020-2021			Thereafter		Total		(Dollars in Thousands)	2020		2021-2022		2023-2024		Thereafter		Total
Prices provided by external sources¹	$	5,381	$	(3,840	)	$	(488	)	$	—	$	1,053	Prices provided by external sources¹	$	9,784	$	(564)	$	(1,937)	$	—	$	7,283
Prices based on internal models and valuation methods	4,791		(1,674		)	(1,521		)	—		1,596		Prices based on internal models and valuation methods	413		(2,282)		(228)		—		(2,097)
Total fair value	$	10,172	$	(5,514	)	$	(2,009	)	$	—	$	2,649	Total fair value	$	10,197	$	(2,846)	$	(2,165)	$	—	$	5,186

_______________


¹	~~Prices provided by external pricing service, which utilizes broker quotes and pricing models.~~

^1.Prices provided by external pricing service, which utilizes broker quotes and pricing models.

For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings, see Note 9,10, "Accounting for Derivative Instruments and Hedging Activities" and Note ~~10,~~11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

Contingent Features and Counterparty Credit Risk

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

PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: WSPP, Inc. (WSPP) agreements which standardize physical power contracts in the electric industry; International Swaps and Derivatives Association (ISDA) agreements which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements which standardize physical natural gas contracts. PSE believes that entering into such agreements reduces the credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss. In order to mitigate concentrated credit risk with a subset of counterparties, PSE ~~executed a futures and cleared swaps agreement in November 2016, with the intent to transact power futures contracts~~transacts on the Intercontinental Exchange (ICE) ~~beginning in early 2017.~~for power futures contracts and ICE NGX for natural gas futures contracts.

Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of December 31, ~~2016,~~2019, PSE held approximately ~~$321.1~~$571.6 million in standby letters of credit or limited parental guarantees and had ~~six~~nine counterparties with unlimited parental guarantees, in support of various electric and natural gas transactions. ~~PSE~~The Company monitors counterparties ~~that are experiencing financial problems, have~~for significant swings in credit default ~~swap~~ rates, ~~have~~ credit rating changes by external rating agencies, ownership changes or ~~have changes in ownership.~~financial distress. As of December 31, ~~2016,~~2019, approximately ~~80%~~27.4% of the Company's total energy portfolio exposure ~~including NPNS transactions, were~~was entered into with investment grade counterparties which, in the majority of cases, do not require collateral calls on the contracts. Counterparty credit risk may impact PSE's decisions on derivative accounting treatment.

Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by Standard & Poor’s and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted-average default tenor for that counterparty’s deals. The default tenor is determined by weighting the fair value and contract tenors for all deals by counterparty and arriving at an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.

The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of credit and non-performance reserves. As of December 31, ~~2016,~~2019, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year. As of December 31, ~~2016,~~2019, PSE had cash posted as collateral of $14.8 million for contracts executed on the ICE. Also, as of December 31, 2019, PSE has posted a $1.0 million letter of credit as a condition of transacting on ~~a physical energy exchange and clearinghouse in Canada.~~the ICE NGX Exchange. PSE did not trigger any collateral requirements with any of its counterparties.

Interest Rate Risk

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

The following table presents the carrying value and fair value of Puget Energy and Puget Sound Energy's debt instruments:


Financial Debt Instruments	December 31, 2019						December 31, 2018
(Dollars in Thousands)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Puget Energy	$	5,920,325	$	7,412,416	$	6,051,788	$	6,984,939
Puget Sound Energy	4,336,142		5,571,818		4,274,157		4,953,908

Financial Debt Instruments December 31, 2016 December 31, 2015
(Dollars in Thousands) Carrying Amount Fair Value
Carrying Amount¹
Fair Value
Puget Energy $ 5,599,836
$ 6,805,791
$ 5,486,522
$ 6,679,008
Puget Sound Energy $ 3,993,061
$ 4,816,807
$ 3,903,366
$ 4,699,621

~~_______________~~


¹	Due to an accounting principle change, the prior year balance sheet as of December 31, 2015 reflect "debt discount, issuance cost and other" in the carrying amount for PE and PSE which was applied retrospectively.

For further details regarding Puget Energy and Puget Sound Energy debt instruments, see Note 6,7, "Long-Term Debt" and Note ~~10,~~11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.

From time to time, PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at December 31, ~~2016~~2019, was a net loss of $5.4 million after tax and accumulated amortization. This compares to an after-tax loss of $5.7 million in OCI as of December 31, ~~2015.~~2018. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors, or a committee of the Board, as applicable and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at December 31, ~~2016.~~2019.

The Company may also enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, ~~2016, Puget Energy~~2019, the Company had ~~two interest rate swap contracts outstanding and PSE did not have any~~no outstanding interest rate swap instruments. At December 31, 2016, the fair value of the interest rate swaps was a $0.1 million pre-tax loss, and matured in January 2017. The fair value considers the risk of Puget Energy’s non-performance by using its incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. Currently, all changes in market value are recorded in earnings.

~~The change in fair value of Puget Energy’s outstanding interest rate swaps from December 31, 2015 through December 31, 2016 is summarized in the table below:~~

Puget Energy
Interest Rate Swap Contracts Asset (Liability)
(Dollars in Thousands)
Fair value of contracts outstanding at December 31, 2015 $ (5,050 )
Contracts realized or otherwise settled during 2016 2,008
Change in fair value of derivatives 2,901
Fair value of contracts outstanding at December 31, 2016 $ (141 )

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



REPORTS:		Page
~~REPORTS:~~
Report of Management and Statement of Responsibility		6364
Report of Independent Registered Public Accounting Firm – Puget Energy		6465
Report of Independent Registered Public Accounting Firm – Puget Sound Energy		656 7

INDEX TO FINANCIAL STATEMENTS:
PUGET ENERGY:
~~Consolidated Statements of Income - Years Ended December 31, 2016, 2015 and 2014~~	66
~~Consolidated Statements of Comprehensive Income - Years Ended December 31, 2016, 2015 and 2014~~		67
~~Consolidated Balance Sheets - December 31, 2016 and 2015~~	68
~~Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2016, 2015 and 2014~~	70
~~Consolidated Statements of Cash Flows - Years Ended December 31, 2016, 2015 and 2014~~	71

~~PUGET SOUND ENERGY:~~
Consolidated Statements of Income - Years Ended December 31, 201~~6, 2015~~9 , 201 8 , and ~~2014~~2017	7269
Consolidated Statements of Comprehensive Income - Years Ended December 31, 201~~6, 2015 and 2014~~9 , 2 018 , 2017		7370
Consolidated Balance Sheets - December 31, 20169 , and ~~2015~~2018		7471
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 201~~6, 2015~~9 , 201 8 , and ~~2014~~2017		7673
Consolidated Statements of Cash Flows - Years Ended December 31, 201~~6, 2015~~9 , 201 8 , and ~~2014~~2017		74

PUGET SOUND ENERGY:
Consolidated Statements of Income - Years Ended December 31, 2019, 2018, and 2017		75
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2019, 2018, 2017		76
Consolidated Balance Sheets - December 31, 2019, and 2018		77
Consolidated Statements of Common Shareholder’s Equity - Years Ended December 31, 2019, 2018, and 2017		79
Consolidated Statements of Cash Flows - Years Ended December 31, 2019, 2018, and 2017		80



NOTES to the Consolidated Financial Statements of Puget Energy and Puget Sound Energy:
Note 1.	Summary of Significant Accounting Policies	7881
Note 2.	New Accounting Pronouncements	8386
Note 3.	Revenue	87
Note 4.	Regulation and Rates	8489
Note 4.5.	Dividend Payment Restrictions	9295
Note 5.6.	Utility Plant	9396
Note 6.7.	Long-Term Debt	9699
Note 7.8.	Liquidity Facilities and Other Financing Arrangements	97101
Note 8.9.	Leases	98102
Note 9.10.	Accounting for Derivative Instruments and Hedging Activities	99105
Note ~~10.~~11.	Fair Value Measurements	~~103~~10 8
Note ~~11.~~12.	Employee Investment Plans	~~107~~112
Note ~~12.~~13.	Retirement Benefits	~~108~~112
Note ~~13.~~14.	Income Taxes	~~114~~120
Note ~~14.~~15.	Litigation	~~116~~123
Note ~~15.~~16.	Commitments and Contingencies	~~117~~124
Note ~~16.~~17.	Related Party Transactions	~~119~~126
Note ~~17.~~18.	Segment Information	~~120~~126
Note ~~18.~~19.	Accumulated Other Comprehensive Income (Loss)	~~120~~127



SUPPLEMENTAL QUARTERLY FINANCIAL DATA		~~123~~129

SCHEDULE:
I. Condensed Financial Information of Puget Energy - December 31, 2019, and 2018, and for the Years Ended December 31, 2019, 2018, and 2017		~~124~~130
II. Valuation and Qualifying Accounts and Reserves		~~128~~
- Years Ended December 31, ~~201~~2019, 2018, 2017~~6, 2015 and 2014~~	134

All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the consolidated financial statements or the notes thereto.

REPORT OF MANAGEMENT AND STATEMENT OF RESPONSIBILITY

PUGET ENERGY, INC.

AND

PUGET SOUND ENERGY, INC.

Puget Energy, Inc. and Puget Sound Energy, Inc. (the Company) management assumes accountability for maintaining compliance with our established financial accounting policies and for reporting our results with objectivity and integrity. The Company believes it is essential for investors and other users of the consolidated financial statements to have confidence that the financial information we provide is timely, complete, relevant and accurate. Management is also responsible to present fairly Puget Energy’s and Puget Sound Energy’s consolidated financial statements, prepared in accordance with GAAP.

Management, with oversight of the Board of Directors, established and maintains a strong ethical climate under the guidance of our Corporate Ethics and Compliance Program so that our affairs are conducted to high standards of proper personal and corporate conduct. Management also established an internal control system that provides reasonable assurance as to the integrity and accuracy of the consolidated financial statements. These policies and practices reflect corporate governance initiatives designed to ensure the integrity and independence of our financial reporting processes including:

1.Our Board has adopted clear corporate governance guidelines.

2.With the exception of the President and Chief Executive Officer, the Board members are independent of management.

3.All members of our key Board committees – the Audit Committee, the Compensation and Leadership Development Committee and the Governance and Public Affairs Committee – are independent of management.

4.The non-management members of our Board meet regularly without the presence of Puget Energy and Puget Sound Energy management.

5.The Charters of our Board committees clearly establish their respective roles and responsibilities.

6.The Company has adopted a ~~Corporate Ethics and Compliance~~ Code of Conduct with a hotline (through an independent third party) available to all employees, and our Audit Committee has procedures in place for the anonymous submission of employee complaints on accounting, internal accounting controls or auditing matters. The Compliance Program is led by the Chief Ethics and Compliance Officer of the Company.

7.Our internal audit control function maintains critical oversight over the key areas of our business and financial processes and controls, and reports directly to our Board Audit Committee.

Management is confident that the internal control structure is operating effectively and will allow the Company to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002.

PricewaterhouseCoopers LLP, our independent registered public accounting firm, reports directly to the Audit Committee of the Board of Directors. PricewaterhouseCoopers LLP’s accompanying report on our consolidated financial statements is based on its audit conducted in accordance with auditing standards prescribed by the Public Company Accounting Oversight Board, including a review of our internal control structure for purposes of designing their audit procedures. Our independent registered accounting firm has reported on the effectiveness of our internal control over financial reporting as required under Section 404 of the Sarbanes-Oxley Act of 2002.

We are committed to improving shareholder value and accept our fiduciary oversight responsibilities. We are dedicated to ensuring that our high standards of financial accounting and reporting as well as our underlying system of internal controls are maintained. Our culture demands integrity and we have confidence in our processes, our internal controls and our people, who are objective in their responsibilities and who operate under a high level of ethical standards.

/s/ Mary E. Kipp

~~Kimberly J. Harris~~

/s/ Daniel A. Doyle

~~Matthew R. Marcelia~~/s/ Stephen J. King

Mary E. Kipp

Daniel A. Doyle

Stephen J. King

President and Chief Executive Officer

Senior Vice President

and Chief Financial Officer

Controller and Principal

Accounting Officer

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of

Puget Energy, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes and financial statement schedules, of Puget Energy, Inc. and its subsidiaries (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements ~~listed in the accompanying index~~referred to above present fairly, in all material respects, the financial position of ~~Puget Energy, Inc. and its subsidiaries~~atthe Company as of December 31, ~~2016~~2019 and ~~December 31, 2015,~~2018, and the results of ~~their~~its operations and ~~their~~its cash flows for each of the three years in the period ended December 31, ~~2016~~2019 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2016,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the ~~Committee of Sponsoring Organizations of~~COSO.

Change in Accounting Principle

As discussed in Note 2 to the ~~Treadway Commission (COSO).~~ consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, ~~and financial statement schedules,~~ for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on ~~these~~the Company’s consolidated financial statements ~~on the financial statement schedules,~~ and on the Company's internal control over financial reporting based on our ~~integrated~~ audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the consolidated financial ~~statements, assessing~~statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, ~~and~~as well as evaluating the overall presentation of the consolidated financial ~~statement presentation.~~statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the

company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Seattle, Washington

~~March 2, 2017~~

February 21, 2020

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~We have served as the Company or its predecessor’s auditor since 1933.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of

Puget Sound Energy, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting.

We have audited the consolidated financial statements, including the related notes and financial statement schedule, of Puget Sound Energy, Inc. and its subsidiary (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements ~~listed in the accompanying index~~referred to above present fairly, in all material respects, the financial position of ~~Puget Sound Energy Inc. and its subsidiary~~atthe Company as of December 31, ~~2016~~2019 and ~~December 31, 2015,~~2018, and the results of ~~their~~its operations and ~~their~~its cash flows for each of the three years in the period ended December 31, ~~2016~~2019 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2016,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the ~~Committee of Sponsoring Organizations of~~COSO.

Change in Accounting Principle

As discussed in Note 2 to the ~~Treadway Commission (COSO).~~ consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, ~~and financial statement schedule,~~ for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on ~~these~~the Company’s consolidated financial statements ~~on the financial statement schedule,~~ and on the Company's internal control over financial reporting based on our ~~integrated~~ audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Definition and Limitations of Internal Control over Financial Reporting

/s/ PricewaterhouseCoopers LLP

Seattle, Washington

~~March 2, 2017~~

February 21, 2020

We have served as the Company or its predecessor’s auditor since 1933.

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Operating revenue:
Electric	$	2,497,041	$	2,455,919	$	2,420,663
Natural gas	875,371		850,748		997,759
Other	28,718		39,829		41,854
Total operating revenue	3,401,130		3,346,496		3,460,276
Operating expenses:
Energy costs:
Purchased electricity	652,560		638,775		590,030
Electric generation fuel	282,864		204,174		206,275
Residential exchange	(79,187)		(77,454)		(75,933)
Purchased natural gas	290,976		296,699		360,009
Unrealized (gain) loss on derivative instruments, net	3,574		(41,662)		30,790
Utility operations and maintenance	596,676		602,638		592,277
Non-utility expense and other	47,907		54,519		53,864
Depreciation and amortization	656,323		666,432		481,969
Conservation amortization	96,571		111,714		121,216
Taxes other than income taxes	333,858		336,603		360,673
Total operating expenses	2,882,122		2,792,438		2,721,170
Operating income (loss)	519,008		554,058		739,106
Other income (deductions):
Other income	59,905		52,957		49,283
Other expense	(9,053)		(11,201)		(14,076)
Interest charges:
AFUDC	14,559		13,695		10,826
Interest expense	(356,638)		(343,795)		(354,802)
Income (loss) before income taxes	227,781		265,714		430,337
Income tax (benefit) expense	17,073		30,092		255,143
Net income (loss)	$	210,708	$	235,622	$	175,194

Year Ended December 31,
2016 2015 2014
Operating revenue:
Electric $ 2,238,492
$ 2,128,468
$ 2,083,797
Natural gas 890,510
947,549
1,012,859
Other 35,299
16,683
16,515
Total operating revenue 3,164,301
3,092,700
3,113,171
Operating expenses:

Energy costs:

Purchased electricity 531,596
499,522
514,087
Electric generation fuel 215,331
249,907
263,493
Residential exchange (69,824 ) (112,473 ) (129,036 )
Purchased natural gas 313,954
403,310
458,691
Unrealized (gain) loss on derivative instruments, net (83,795 ) (13,233 ) 84,146
Utility operations and maintenance 568,492
530,720
550,146
Non-utility expense and other 27,151
10,818
13,109
Depreciation and amortization 439,579
420,807
365,606
Conservation amortization 107,784
110,866
104,096
Taxes other than income taxes 328,649
320,531
310,982
Total operating expenses 2,378,917
2,420,775
2,535,320
Operating income (loss) 785,384
671,925
577,851
Other income (deductions):

Other income 25,539
20,711
24,038
Other expense (10,923 ) (6,764 ) (7,457 )
Non-hedged interest rate swap expense (1,062 ) (3,796 ) (3,915 )
Interest charges:

AFUDC 9,304
7,575
5,611
Interest expense (355,139 ) (356,696 ) (367,308 )
Income (loss) before income taxes 453,103
332,955
228,820
Income tax (benefit) expense 140,204
91,776
56,985
Net income (loss) $ 312,899
$ 241,179
$ 171,835

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	210,708	$	235,622	$	175,194
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(1,846) and $(12,677) and $5,078, respectively	(6,947)		(47,690)		9,430

Reclassification of stranded taxes to retained earnings due to tax reform	—		(5,230)		—
Other comprehensive income (loss)	(6,947)		(52,920)		9,430
Comprehensive income (loss)	$	203,761	$	182,702	$	184,624

Year Ended December 31,
2016 2015 2014
Net income (loss) $ 312,899
$ 241,179
$ 171,835
Other comprehensive income (loss):

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(3,471), $5,087 and $(45,890), respectively (6,446 ) 9,444
(85,224 )
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $179 and $200, respectively —
333
372
Reclassification of net unrealized (gain) loss on interest rate swaps, net of tax of $0, $0 and $50, respectively —
—
94
Other comprehensive income (loss) (6,446 ) 9,777
(84,758 )
Comprehensive income (loss) $ 306,453
$ 250,956
$ 87,077

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

~~PUGET ENERGY, INC.~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Dollars in Thousands)~~

~~ASSETS~~

December 31,
2016 2015
Utility plant (at original cost, including construction work in progress of $420,278 and $408,795, respectively):
Electric plant $ 7,673,772
$ 7,432,490
Natural gas plant 3,051,586
2,850,290
Common plant 594,994
508,750
Less: Accumulated depreciation and amortization (2,161,796 ) (1,878,868 )
Net utility plant 9,158,556
8,912,662
Other property and investments:

Goodwill 1,656,513
1,656,513
Other property and investments 106,418
86,731
Total other property and investments 1,762,931
1,743,244
Current assets:

Cash and cash equivalents 28,878
42,494
Restricted cash 12,418
7,949
Accounts receivable, net of allowance for doubtful accounts of $9,798 and $9,756, respectively 329,375
324,391
Unbilled revenue 234,053
217,274
Purchased gas adjustment receivable 2,785
—
Materials and supplies, at average cost 106,378
78,244
Fuel and natural gas inventory, at average cost 58,181
58,658
Unrealized gain on derivative instruments 54,341
24,418
Prepaid expense and other 43,046
17,120
Power contract acquisition adjustment gain 33,413
37,031
Total current assets 902,868
807,579
Other long-term and regulatory assets:

Regulatory asset for deferred income taxes 72,038
73,231
Power cost adjustment mechanism 4,531
4,749
Regulatory assets related to power contracts 22,613
26,223
Other regulatory assets 1,034,348
894,071
Unrealized gain on derivative instruments 8,738
5,225
Power contract acquisition adjustment gain 241,648
288,757
Other 58,109
58,513
Total other long-term and regulatory assets 1,442,025
1,350,769
Total assets $ 13,266,380
$ 12,814,254

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

~~CAPITALIZATION AND LIABILITIES~~ASSETS


	December 31,
	2019		2018
Utility plant (at original cost, including construction work in progress of $591,199 and $550,466, respectively):
Electric plant	$	8,811,889	$	8,515,482
Natural gas plant	3,916,040		3,598,732
Common plant	1,096,649		1,027,023
Less: Accumulated depreciation and amortization	(3,236,240)		(2,832,321)
Net utility plant	10,588,338		10,308,916
Other property and investments:
Goodwill	1,656,513		1,656,513
Other property and investments	286,975		244,444
Total other property and investments	1,943,488		1,900,957
Current assets:
Cash and cash equivalents	45,259		37,521
Restricted cash	20,887		18,041
Accounts receivable, net of allowance for doubtful accounts of $8,294 and $8,408, respectively	316,352		338,782
Unbilled revenue	224,657		205,285
Purchased gas adjustment receivable	—		9,921
Materials and supplies, at average cost	115,684		116,180
Fuel and natural gas inventory, at average cost	52,083		53,351
Unrealized gain on derivative instruments	23,626		46,507
Prepaid expenses and other	27,504		25,674
Power contract acquisition adjustment gain	9,067		6,114
Total current assets	835,119		857,376
Other long-term and regulatory assets:
Power cost adjustment mechanism	41,745		4,735
Purchased gas adjustment receivable	132,766		—
Regulatory assets related to power contracts	14,146		16,693
Other regulatory assets	673,021		773,552
Unrealized gain on derivative instruments	7,682		2,512
Power contract acquisition adjustment gain	147,530		156,597
Operating lease right-of-use asset	183,048		—
Other	92,980		77,523
Total other long-term and regulatory assets	1,292,918		1,031,612
Total assets	$	14,659,863	$	14,098,861

December 31,
2016 2015
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding $ —
$ —
Additional paid-in capital 3,308,957
3,308,957
Retained earnings 413,468
249,534
Accumulated other comprehensive income (loss), net of tax (33,712 ) (27,266 )
Total common shareholder’s equity 3,688,713
3,531,225
Long-term debt:

First mortgage bonds and senior notes 3,362,000
3,364,412
Pollution control bonds 161,860
161,860
Junior subordinated notes 250,000
250,000
Long-term debt 1,812,480
1,800,000
Debt discount, issuance costs and other (234,679 ) (248,754 )
Total long-term debt 5,351,661
5,327,518
Total capitalization 9,040,374
8,858,743
Current liabilities:

Accounts payable 317,043
259,353
Short-term debt 245,763
159,004
Current maturities of long-term debt 2,412
—
Purchased gas adjustment liability —
12,589
Accrued expenses:

Taxes 111,428
114,854
Salaries and wages 49,749
38,457
Interest 73,610
73,378
Unrealized loss on derivative instruments 44,310
136,173
Power contract acquisition adjustment loss 3,159
3,611
Other 71,996
53,867
Total current liabilities 919,470
851,286
Other Long-term and regulatory liabilities:

Deferred income taxes 1,570,931
1,435,955
Unrealized loss on derivative instruments 16,261
48,073
Regulatory liabilities 654,622
652,441
Regulatory liabilities related to power contracts 275,061
325,788
Power contract acquisition adjustment loss 19,454
22,613
Other deferred credits 770,207
619,355
Total other long-term and regulatory liabilities 3,306,536
3,104,225
Commitments and contingencies (Note 15)

Total capitalization and liabilities $ 13,266,380
$ 12,814,254

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

PUGET ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES


	December 31,
	2019		2018
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—	$	—
Additional paid-in capital	3,308,957		3,308,957
Retained earnings	775,491		629,003
Accumulated other comprehensive income (loss), net of tax	(84,149)		(77,202)
Total common shareholder’s equity	4,000,299		3,860,758
Long-term debt:
First mortgage bonds and senior notes	4,212,000		3,764,412
Pollution control bonds	161,860		161,860

Long-term debt	1,758,100		1,961,900
Debt discount, issuance costs and other	(211,635)		(215,681)
Total long-term debt	5,920,325		5,672,491
Total capitalization	9,920,624		9,533,249
Current liabilities:
Accounts payable	325,913		480,069
Short-term debt	176,000		379,297
Current maturities of long-term debt	452,412		—

Accrued expenses:
Taxes	99,979		118,112
Salaries and wages	50,091		50,785
Interest	74,855		70,099
Unrealized loss on derivative instruments	13,428		46,661
Power contract acquisition adjustment loss	2,418		2,547
Operating lease liabilities	15,862		—
Other	107,809		79,312
Total current liabilities	1,318,767		1,226,882
Other Long-term and regulatory liabilities:
Deferred income taxes	824,720		789,297
Unrealized loss on derivative instruments	12,693		11,095
Regulatory liabilities	730,879		747,203
Regulatory liability for deferred income taxes	946,179		975,974
Regulatory liabilities related to power contracts	156,597		162,711
Power contract acquisition adjustment loss	11,728		14,146
Operating lease liabilities	174,327		—
Other deferred credits	563,349		638,304
Total long-term and regulatory liabilities	3,420,472		3,338,730
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$	14,659,863	$	14,098,861

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock					Additional				Accumulated Other
	Shares	Amount		Paid-in Capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2016	200	$	—	$	3,308,957	$	413,468	$	(33,712)	$	3,688,713
Net income (loss)	—	—		—		175,194		—		175,194
Common stock dividend paid	—	—		—		(123,307)		—		(123,307)
Other comprehensive income (loss)	—	—		—		—		9,430		9,430
Balance at December 31, 2017	200	$	—	$	3,308,957	$	465,355	$	(24,282)	$	3,750,030
Net income (loss)	—	—		—		235,622		—		235,622
Common stock dividend paid	—	—		—		(77,204)		—		(77,204)
Other comprehensive income (loss)	—	—		—		—		(52,920)		(52,920)
Cumulative effect of accounting change	—	—		—		5,230		—		5,230
Balance at December 31, 2018	200	$	—	$	3,308,957	$	629,003	$	(77,202)	$	3,860,758
Net income (loss)	—	—		—		210,708		—		210,708
Common stock dividend paid	—	—		—		(64,220)		—		(64,220)
Other comprehensive income (loss)	—	—		—		—		(6,947)		(6,947)

Balance at December 31, 2019	200	$	—	$	3,308,957	$	775,491	$	(84,149)	$	4,000,299

Common Stock Additional Accumulated Other
Shares Amount
Paid-in
Capital
Retained Earnings
Comprehensive
Income (Loss)
Total
Equity
Balance at December 31, 2013 200
$ —
$ 3,308,957
$ 323,007
$ 47,715
$ 3,679,679
Net income (loss) —
—
—
171,835
—
171,835
Common stock dividend —
—
—
(223,428 ) —
(223,428 )
Other comprehensive income (loss) —
—
—
—
(84,758 ) (84,758 )
Balance at December 31, 2014 200
$ —
$ 3,308,957
$ 271,414
$ (37,043 ) $ 3,543,328
Net income (loss) —
—
—
241,179
—
241,179
Common stock dividend —
—
—
(263,059 ) —
(263,059 )
Other comprehensive income (loss) —
—
—
—
9,777
9,777
Balance at December 31, 2015 200
$ —
$ 3,308,957
$ 249,534
$ (27,266 ) $ 3,531,225
Net income (loss) —
—
—
312,899
—
312,899
Common stock dividend —
—
—
(148,965 ) —
(148,965 )
Other comprehensive income (loss) —
—
—
—
(6,446 ) (6,446 )
Balance at December 31, 2016 200
$ —
$ 3,308,957
$ 413,468
$ (33,712 ) $ 3,688,713

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

PUGET ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


											Year Ended December 31,
	Year Ended December 31,										2019		2018		2017
	2016			2015			2014
Operating activities:
Net income (loss)	$	312,899		$	241,179		$	171,835
Operating Activities:										Operating Activities:
Net Income (Loss)										Net Income (Loss)	$	210,708	$	235,622	$	175,194
Adjustments to reconcile net income (loss) to net cash provided by operating activities:										Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	439,579			420,807			365,606			Depreciation and amortization	656,323		666,432		481,969
Conservation amortization	107,784			110,866			104,096			Conservation amortization	96,571		111,714		121,216
Deferred income taxes and tax credits, net	139,640			91,978			56,984			Deferred income taxes and tax credits, net	7,475		19,457		254,524
Net unrealized (gain) loss on derivative instruments	(88,704		)	(17,255		)	80,139			Net unrealized (gain) loss on derivative instruments	3,574		(41,662)		30,650
Derivative contracts classified as financing activities due to merger	—			8,045			16,349
AFUDC - equity	(12,576		)	(9,325		)	(7,002		)	AFUDC - equity	(15,802)		(17,191)		(15,027)
Production tax credit										Production tax credit	(68,622)		(83,976)		(53,331)
Other non-cash										Other non-cash	(4,639)		15,339		17,568
Funding of pension liability	(24,000		)	(18,000		)	(18,000		)	Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	(150,855		)	(153,877		)	(228,334		)	Regulatory assets and liabilities	(79,233)		(71,348)		(88,875)
Other long-term assets and liabilities	30,459			35,270			19,691
Purchased gas adjustment										Purchased gas adjustment	(132,766)		—		—
Other long term assets and liabilities										Other long term assets and liabilities	(16,098)		2,695		(27,411)
Change in certain current assets and liabilities:										Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(21,763		)	(66,703		)	153,434			Accounts receivable and unbilled revenue	3,058		17,659		132
Materials and supplies	(28,134		)	4,945			4,951			Materials and supplies	(6,018)		(9,177)		(625)
Fuel and natural gas inventory	473			9,332			(2,742		)	Fuel and natural gas inventory	1,268		(3,443)		8,266
Purchased gas adjustment										Purchased gas adjustment	9,921		(25,972)		18,836
Prepayments and other	(25,927		)	4,086			(2,140		)	Prepayments and other	(1,103)		(3,679)		21,050
Purchased gas adjustment	(15,374		)	33,662			(27,011		)
Accounts payable	32,465			(48,037		)	9,098			Accounts payable	(116,311)		117,270		26,396
Taxes payable	(3,426		)	7,072			(1,777		)	Taxes payable	(18,133)		164		6,520
Other	36,750			(5,323		)	6,605			Other	15,163		(7,723)		13,079
Net cash provided by (used in) operating activities	729,290			648,722			701,782			Net cash provided by (used in) operating activities	527,336		904,181		972,131
Investing activities:										Investing activities:
Construction expenditures - excluding equity AFUDC	(706,444		)	(587,225		)	(493,130		)	Construction expenditures - excluding equity AFUDC	(959,387)		(1,072,670)		(1,040,135)
Treasury grants received	—			—			107,876
Proceeds from disposition of assets	—			—			20,296
Restricted cash	(4,469		)	24,914			(25,692		)
Other	(1,921		)	754			(4,512		)	Other	6,908		2,097		(195)
Net cash provided by (used in) investing activities	(712,834		)	(561,557		)	(395,162		)	Net cash provided by (used in) investing activities	(952,479)		(1,070,573)		(1,040,330)
Financing activities:
Financing Activities:										Financing Activities:
Change in short-term debt, net	86,759			74,004			(77,000		)	Change in short-term debt, net	(203,297)		49,834		83,700
Dividends paid	(148,965		)	(263,059		)	(223,428		)	Dividends paid	(64,220)		(77,204)		(123,307)

Proceeds from long-term debt and bonds issued	12,481			825,000			299,000			Proceeds from long-term debt and bonds issued	689,351		804,050		90,120
Redemption of bonds and notes	—			(711,000		)	(299,000		)	Redemption of bonds and notes	—		(600,000)		—
Derivative contracts classified as financing activities due to merger	—			(8,045		)	(16,349		)
Other	19,653			902			3,382			Other	13,893		8,513		13,151
Net cash provided by (used in) financing activities	(30,072		)	(82,198		)	(313,395		)	Net cash provided by (used in) financing activities	435,727		185,193		63,664
Net increase (decrease) in cash and cash equivalents	(13,616		)	4,967			(6,775		)
Cash and cash equivalents at beginning of period	42,494			37,527			44,302
Cash and cash equivalents at end of period	$	28,878		$	42,494		$	37,527
Net increase (decrease) in cash, cash equivalents, and restricted cash										Net increase (decrease) in cash, cash equivalents, and restricted cash	10,584		18,801		(4,535)
Cash, cash equivalents, and restricted cash at beginning of period										Cash, cash equivalents, and restricted cash at beginning of period	55,562		36,761		41,296
Cash, cash equivalents, and restricted cash at end of period										Cash, cash equivalents, and restricted cash at end of period	66,146		55,562		36,761
Supplemental cash flow information:										Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	329,603		$	339,866		$	349,402		Cash payments for interest (net of capitalized interest)	$	328,703	$	322,476	$	326,798
Cash payments (refunds) for income taxes	—			2			—			Cash payments (refunds) for income taxes	10,616		8,303		1,649

Non-cash financing and investing activities:										Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	76,813		$	51,588		$	51,776
Accounts payable for capital expenditures eliminated from cash flow										Accounts payable for capital expenditures eliminated from cash flow	$	58,329	$	97,673	$	92,959
Reclassification of Colstrip from utility plant to a regulatory asset	176,804			—			—			Reclassification of Colstrip from utility plant to a regulatory asset	4,163		(3,086)		(49,177)
Reclassification of hydro treasury grants to a regulatory liability										Reclassification of hydro treasury grants to a regulatory liability	$	—	$	—	$	95,935

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Operating revenue:
Electric	$	2,497,041	$	2,455,919	$	2,420,663
Natural gas	875,371		850,748		997,759
Other	28,718		39,829		41,854
Total operating revenue	3,401,130		3,346,496		3,460,276
Operating expenses:
Energy costs:
Purchased electricity	652,560		638,775		590,030
Electric generation fuel	282,864		204,174		206,275
Residential exchange	(79,187)		(77,454)		(75,933)
Purchased natural gas	290,976		296,699		360,009
Unrealized (gain) loss on derivative instruments, net	3,574		(41,662)		30,790
Utility operations and maintenance	596,676		602,638		592,277
Non-utility expense and other	44,403		51,549		52,389
Depreciation and amortization	656,220		666,324		481,955
Conservation amortization	96,571		111,714		121,216
Taxes other than income taxes	333,858		336,603		360,673
Total operating expenses	2,878,515		2,789,360		2,719,681
Operating income (loss)	522,615		557,136		740,595
Other income (deductions):
Other income	47,766		39,847		34,867
Other expense	(9,053)		(11,201)		(14,104)

Interest charges:
AFUDC	14,559		13,695		10,826
Interest expense	(243,815)		(231,615)		(240,144)
Income (loss) before income taxes	332,072		367,862		532,040
Income tax (benefit) expense	39,148		50,700		211,986
Net income (loss)	$	292,924	$	317,162	$	320,054

Year Ended December 31,
2016 2015 2014
Operating revenue:
Electric $ 2,238,492
$ 2,128,468
$ 2,083,797
Natural gas 890,510
947,549
1,012,859
Other 35,616
17,241
19,467
Total operating revenue 3,164,618
3,093,258
3,116,123
Operating expenses:

Energy costs:

Purchased electricity 531,596
499,522
514,087
Electric generation fuel 215,331
249,907
263,493
Residential exchange (69,824 ) (112,473 ) (129,036 )
Purchased natural gas 313,954
403,310
458,691
Unrealized (gain) loss on derivative instruments, net (83,795 ) (12,688 ) 85,636
Utility operations and maintenance 568,492
530,720
550,146
Non-utility expense and other 37,859
26,618
23,729
Depreciation and amortization 439,579
420,807
365,606
Conservation amortization 107,784
110,866
104,096
Taxes other than income taxes 328,649
320,531
310,982
Total operating expenses 2,389,625
2,437,120
2,547,430
Operating income (loss) 774,993
656,138
568,693
Other income (deductions):

Other income 25,537
20,711
24,036
Other expense (10,923 ) (6,764 ) (7,457 )
Interest charges:

AFUDC 9,304
7,575
5,611
Interest expense (242,983 ) (247,571 ) (264,927 )
Income (loss) before income taxes 555,928
430,089
325,956
Income tax (benefit) expense 175,347
125,900
89,342
Net income (loss) $ 380,581
$ 304,189
$ 236,614

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	292,924	$	317,162	$	320,054
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax of $539, $(9,844) and $9,848, respectively	2,022		(37,030)		18,288
Amortization of treasury interest rate swaps to earnings, net of tax of $102, $102 and $171, respectively	385		385		317
Reclassification of stranded taxes to retained earnings due to tax reform	—		(27,333)		—
Other comprehensive income (loss)	2,407		(63,978)		18,605
Comprehensive income (loss)	$	295,331	$	253,184	$	338,659

Year Ended December 31,
2016 2015 2014
Net income (loss) $ 380,581
$ 304,189
$ 236,614
Other comprehensive income (loss):

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $2,004, $10,987 and $(41,395), respectively 3,722
20,404
(76,876 )
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $369 and $722, respectively —
686
1,341
Amortization of treasury interest rate swaps to earnings, net of tax of $171, $171 and $171, respectively 317
317
317
Other comprehensive income (loss) 4,039
21,407
(75,218 )
Comprehensive income (loss) $ 384,620
$ 325,596
$ 161,396

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

~~PUGET SOUND ENERGY, INC.~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Dollars in Thousands)~~

~~ASSETS~~

December 31,
2016 2015
Utility plant (at original cost, including construction work in progress of $420,278 and $408,795, respectively):
Electric plant $ 9,813,169
$ 9,601,091
Natural gas plant 3,640,271
3,444,744
Common plant 632,718
548,657
Less: Accumulated depreciation and amortization (4,927,602 ) (4,681,830 )
Net utility plant 9,158,556
8,912,662
Other property and investments:

Other property and investments 77,960
83,069
Total other property and investments 77,960
83,069
Current assets:

Cash and cash equivalents 28,481
41,856
Restricted cash 12,418
7,949
Accounts receivable, net of allowance for doubtful accounts of $9,798 and $9,756, respectively 344,964
324,358
Unbilled revenue 234,053
217,274
Purchased gas adjustment receivable 2,785
—
Materials and supplies, at average cost 106,378
78,244
Fuel and natural gas inventory, at average cost 56,851
57,324
Unrealized gain on derivative instruments 54,341
24,418
Prepaid expenses and other 43,046
17,119
Total current assets 883,317
768,542
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes 71,517
72,694
Power cost adjustment mechanism 4,531
4,749
Other regulatory assets 1,034,352
894,059
Unrealized gain on derivative instruments 8,738
5,225
Other 58,109
58,513
Total other long-term and regulatory assets 1,177,247
1,035,240
Total assets $ 11,297,080
$ 10,799,513

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

~~CAPITALIZATION AND LIABILITIES~~ASSETS


	December 31,
	2019		2018
Utility plant (at original cost, including construction work in progress of $591,199 and $550,466, respectively):
Electric plant	$	10,671,328	$	10,587,231
Natural gas plant	4,478,048		4,164,489
Common plant	1,121,568		1,052,544
Less: Accumulated depreciation and amortization	(5,682,606)		(5,495,348)
Net utility plant	10,588,338		10,308,916
Other property and investments:
Other property and investments	81,112		76,986
Total other property and investments	81,112		76,986
Current assets:
Cash and cash equivalents	44,004		35,452
Restricted cash	20,887		18,041
Accounts receivable, net of allowance for doubtful accounts of $8,294 and $8,408, respectively	319,229		346,251
Unbilled revenue	224,657		205,285
Purchased gas adjustment receivable	—		9,921
Materials and supplies, at average cost	115,684		116,180
Fuel and natural gas inventory, at average cost	50,818		52,028
Unrealized gain on derivative instruments	23,626		46,507
Prepaid expenses and other	27,504		25,674
Total current assets	826,409		855,339
Other long-term and regulatory assets:
Power cost adjustment mechanism	41,745		4,735
Purchased gas adjustment receivable	132,766		—
Other regulatory assets	673,021		773,552
Unrealized gain on derivative instruments	7,682		2,512
Operating lease right-of-use asset	183,048		—
Other	90,924		75,483
Total other long-term and regulatory assets	1,129,186		856,282
Total assets	$	12,625,045	$	12,097,523

December 31,
2016 2015
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding $ 859
$ 859
Additional paid-in capital 3,275,105
3,275,105
Retained earnings 359,795
236,578
Accumulated other comprehensive income (loss), net of tax (145,511 ) (149,550 )
Total common shareholder’s equity 3,490,248
3,362,992
Long-term debt:

First mortgage bonds and senior notes 3,362,000
3,364,412
Pollution control bonds 161,860
161,860
Junior subordinated notes 250,000
250,000
Debt discount, issuance costs and other (28,974 ) (31,910 )
Total long-term debt 3,744,886
3,744,362
Total capitalization 7,235,134
7,107,354
Current liabilities:

Accounts payable 317,043
259,353
Short-term debt 245,763
159,004
Current maturities of long-term debt 2,412
—
Purchased gas adjustment liability —
12,589
Accrued expenses:

Taxes 111,428
114,854
Salaries and wages 49,749
38,457
Interest 48,087
47,772
Unrealized loss on derivative instruments 44,170
131,420
Other 71,996
53,868
Total current liabilities 890,648
817,317
Other Long-term and regulatory liabilities:

Deferred income taxes 1,732,390
1,556,616
Unrealized loss on derivative instruments 16,261
47,776
Regulatory liabilities 653,296
651,094
Other deferred credits 769,351
619,356
Total other long-term and regulatory liabilities 3,171,298
2,874,842
Commitments and contingencies (Note 15)

Total capitalization and liabilities $ 11,297,080
$ 10,799,513

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES


	Year Ended December 31,
	2019		2018
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859	$	859
Additional paid-in capital	3,485,105		3,275,105
Retained earnings	751,193		622,844
Accumulated other comprehensive income (loss), net of tax	(188,477)		(190,884)
Total common shareholder’s equity	4,048,680		3,707,924
Long-term debt:
First mortgage bonds and senior notes	4,212,000		3,764,417
Pollution control bonds	161,860		161,860

Debt discount, issuance costs and other	(37,718)		(31,417)
Total long-term debt	4,336,142		3,894,860
Total capitalization	8,384,822		7,602,784
Current liabilities:
Accounts payable	325,980		480,195
Short-term debt	176,000		379,297
Current maturities of long-term debt	2,412		—

Accrued expenses:
Taxes	99,977		117,993
Salaries and wages	50,091		50,785
Interest	48,917		43,951
Unrealized loss on derivative instruments	13,428		46,661
Operating lease liabilities	15,862		—
Other	107,809		79,312
Total current liabilities	840,476		1,198,194
Other Long-term and regulatory liabilities:
Deferred income taxes	977,163		926,403
Unrealized loss on derivative instruments	12,693		11,095
Regulatory liabilities	729,614		745,880
Regulatory liability for deferred income taxes	946,936		976,582
Operating lease liabilities	174,327		—
Other deferred credits	559,014		636,585
Total long-term and regulatory liabilities	3,399,747		3,296,545
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$	12,625,045	$	12,097,523

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)



	Common Stock						Additional				Accumulated Other
	Shares		Amount		Paid-in Capital		Retained Earnings		Comprehensive Income (Loss)		Total Equity
Balance at December 31, 2016	$	85,903,791	$	859	$	3,275,105	$	359,795	$	(145,511)	$	3,490,248
Net income (loss)	—		—		—		320,054		—		320,054
Common stock dividend paid	—		—		—		(227,783)		—		(227,783)

Other comprehensive income (loss)	—		—		—		—		18,605		18,605
Balance at December 31, 2017	$	85,903,791	$	859	$	3,275,105	$	452,066	$	(126,906)	$	3,601,124
Net income (loss)	—		—		—		317,162		—		317,162
Common stock dividend paid	—		—		—		(173,716)		—		(173,716)

Other comprehensive income (loss)	—		—		—		—		(63,978)		(63,978)
Cumulative effect of accounting change	—		—		—		27,332		—		27,332
Balance at December 31, 2018	$	85,903,791	$	859	$	3,275,105	$	622,844	$	(190,884)	$	3,707,924
Net income (loss)	—		—		—		292,924		—		292,924
Common stock dividend paid	—		—		—		(164,575)		—		(164,575)
Capital Contribution	—		—		210,000		—		—		210,000
Other comprehensive income (loss)	—		—		—		—		2,407		2,407

Balance at December 31, 2019	$	85,903,791	$	859	$	3,485,105	$	751,193	$	(188,477)	$	4,048,680

Common Stock Additional Accumulated Other
Shares Amount
Paid-in
Capital
Retained Earnings
Comprehensive
Income (loss)
Total
Equity
Balance at December 31, 2013 85,903,791
$ 859
$ 3,246,205
$ 289,432
$ (95,739 ) $ 3,440,757
Net income (loss) —
—
—
236,614
—
236,614
Common stock dividend —
—
—
(323,424 ) —
(323,424 )
Other comprehensive income (loss) —
—
—
—
(75,218 ) (75,218 )
Balance at December 31, 2014 85,903,791
$ 859
$ 3,246,205
$ 202,622
$ (170,957 ) $ 3,278,729
Net income (loss) —
—
—
304,189
—
304,189
Common stock dividend —
—
—
(270,233 ) —
(270,233 )
Capital Contribution —
—
28,900
—
—
28,900
Other comprehensive income (loss) —
—
—
—
21,407
21,407
Balance at December 31, 2015 85,903,791
$ 859
$ 3,275,105
$ 236,578
$ (149,550 ) $ 3,362,992
Net income (loss) —
—
—
380,581
—
380,581
Common stock dividend —
—
—
(257,364 ) —
(257,364 )
Other comprehensive income (loss) —
—
—
—
4,039
4,039
Balance at December 31, 2016 85,903,791
$ 859
$ 3,275,105
$ 359,795
$ (145,511 ) $ 3,490,248

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

PUGET SOUND ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Operating Activities:
Net Income (Loss)	$	292,924	$	317,162	$	320,054
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	656,220		666,324		481,955
Conservation amortization	96,571		111,714		121,216
Deferred income taxes and tax credits, net	20,474		30,995		210,842
Net unrealized (gain) loss on derivative instruments	3,574		(41,662)		30,790
AFUDC - equity	(15,802)		(17,191)		(15,027)
Production tax credit	(68,622)		(83,976)		(53,331)
Other non-cash	(15,154)		4,428		6,445
Funding of pension liability	(18,000)		(18,000)		(18,000)
Regulatory assets and liabilities	(79,173)		(71,348)		(88,875)
Purchased gas adjustment	(132,766)		—		—
Other long term assets and liabilities	(8,967)		16,917		(14,547)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	7,650		12,626		13,285
Materials and supplies	(6,018)		(9,177)		(625)
Fuel and natural gas inventory	1,210		(3,443)		8,266
Purchased gas adjustment	9,921		(25,972)		18,836
Prepayments and other	(1,103)		(3,679)		21,050
Accounts payable	(116,370)		117,397		26,396
Taxes payable	(18,016)		930		5,635
Other	15,371		(8,141)		12,438
Net cash provided by (used in) operating activities	623,924		995,904		1,086,803
Investing Activities:
Construction expenditures - excluding equity AFUDC	(919,271)		(1,010,506)		(963,652)
Other	6,908		2,097		241
Net cash provided by (used in) investing activities	(912,363)		(1,008,409)		(963,411)
Financing Activities
Change in short-term debt, net	(203,297)		49,834		83,700
Dividends paid	(164,575)		(173,716)		(227,783)

Investment from Parent	210,000		—		—
Proceeds from long-term debt and bonds issued	443,151		594,750		—
Redemption of bonds and notes	—		(450,000)		—
Other	14,558		9,121		15,801
Net cash provided by (used in) financing activities	299,837		29,989		(128,282)
Net increase (decrease) in cash, cash equivalents, and restricted cash	11,398		17,484		(4,890)
Cash, cash equivalents, and restricted cash at beginning of period	53,493		36,009		40,899
Cash, cash equivalents, and restricted cash at end of period	$	64,891	$	53,493	$	36,009
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	219,665	$	221,155	$	224,423
Cash payments (refunds) for income taxes	19,269		18,124		3,058


Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flow	$	58,329	$	97,673	$	92,959
Reclassification of Colstrip from utility plant to a regulatory asset	4,163		(3,086)		(49,177)
Reclassification of hydro treasury grants to a regulatory liability	—		—		95,935

Year Ended December 31,
2016 2015 2014
Operating activities:
Net income (loss) $ 380,581
$ 304,189
$ 236,614
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization 439,579
420,807
365,606
Conservation amortization 107,784
110,866
104,096
Deferred income taxes and tax credits, net 174,776
125,900
89,342
Net unrealized (gain) loss on derivative instruments (83,795 ) (12,688 ) 85,636
AFUDC - equity (12,576 ) (9,325 ) (7,002 )
Funding of pension liability (24,000 ) (18,000 ) (18,000 )
Regulatory assets and liabilities (149,998 ) (153,877 ) (228,334 )
Other long-term assets and liabilities 33,119
39,379
16,518
Change in certain current assets and liabilities:

Accounts receivable and unbilled revenue (37,385 ) (66,547 ) 153,626
Materials and supplies (28,134 ) 4,945
4,951
Fuel and natural gas inventory 473
9,332
(2,742 )
Prepayments and other (25,927 ) 4,089
(2,140 )
Purchased gas adjustment (15,374 ) 33,662
(27,011 )
Accounts payable 32,465
(48,031 ) 9,098
Taxes payable (3,426 ) 7,072
(1,777 )
Other 30,754
(12,992 ) 4,246
Net cash provided by (used in) operating activities 818,916
738,781
782,727
Investing activities:

Construction expenditures - excluding equity AFUDC (681,112 ) (587,225 ) (493,130 )
Treasury grants received —
—
107,876
Proceeds from disposition of assets —
—
20,296
Restricted cash (4,469 ) 24,914
(25,692 )
Other 4,156
6,386
(1,683 )
Net cash provided by (used in) investing activities (681,425 ) (555,925 ) (392,333 )
Financing activities:

Change in short-term debt, net 86,759
74,004
(77,000 )
Dividends paid (257,364 ) (270,233 ) (323,424 )
Loan from (payment to) parent —
(28,933 ) (665 )
Investment from parent —
28,900
—
Proceeds from long-term debt and bonds issued —
425,000
—
Redemption of bonds and notes —
(412,000 ) —
Other 19,739
4,796
4,050
Net cash provided by (used in) financing activities (150,866 ) (178,466 ) (397,039 )
Net increase (decrease) in cash and cash equivalents (13,375 ) 4,390
(6,645 )
Cash and cash equivalents at beginning of period 41,856
37,466
44,111
Cash and cash equivalents at end of period $ 28,481
$ 41,856
$ 37,466
Supplemental cash flow information:

Cash payments for interest (net of capitalized interest) $ 227,668
$ 242,774
$ 253,803
Cash payments (refunds) for income taxes —
2
—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows $ 76,813
$ 51,588
$ 51,776
Reclassification of Colstrip from utility plant to a regulatory asset

176,804
—
—

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

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Basis of Presentation

Puget Energy ~~Inc. (Puget Energy)~~ is an energy services holding company that owns Puget Sound Energy ~~Inc.~~ (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature.

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

The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the ~~Company.”~~Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and ~~PSE’s financial statements~~ do not include any ~~ASC~~Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

~~Change in Accounting Principle~~

On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with Accounting Standards Update (ASU) 2015-03, ~~"Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs"~~. ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased 38.4 million and 30.0 million at Puget Energy and PSE, respectively.

Utility Plant

Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability.

Planned Major Maintenance

Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment ~~on its natural gas fired combustion turbines~~ on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities.

~~Non-Utility~~Other Property ~~Plant~~ and ~~Equipment~~Investments

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

Depreciation and Amortization

~~For financial statement purposes, the~~The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The ~~depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The~~ annual depreciation provision stated as a percent of a depreciable electric utility plant was ~~2.8%~~3.4%, ~~for each of 2016, 2015~~3.3%, and ~~2014;~~2.8% in 2019, 2018, and 2017, respectively; depreciable natural gas

utility plant was ~~3.4%~~2.8%, ~~for each of 2016, 2015~~2.8%, and ~~2014;~~3.4% in 2019, 2018, and 2017, respectively; and depreciable common utility plant was ~~9.7%~~7.3%, ~~8.5%~~7.1% and ~~8.5%~~8.3% in ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively. ~~Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets.~~ The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.

~~Goodwill~~Tacoma LNG Facility

In ~~2009,~~August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget ~~Holdings completed its merger~~Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice.

Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget ~~Energy.~~LNG. Per this allocation of costs, $199.9 million and $165.6 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy ~~remeasured the carrying amount~~"Other property and investments" financial statement line item as of ~~all its assets~~December 31, 2019, and ~~liabilities to fair value, which resulted in recognition~~December 31, 2018, respectively. Additionally, $1.2 million, $2.0 million, and $0.3 million 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 changeoperating costs are reported in the ~~Company’s business or regulatory outlook, legal factors, a sale or disposition~~Puget Energy "Non-utility expense and other" financial statement line item in 2019, 2018, and 2017, respectively. Additionally, $162.8 million and $130.8 million of ~~a significant~~construction work in progress related to PSE’s portion of ~~a reporting unit or significant changes~~the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” 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.~~

~~Puget Energy conducted its annual impairment test in~~ ~~2016~~ ~~using an October 1,~~ ~~2016~~ measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwillstatement line item as of ~~October 1, 2016. There were no known events or circumstances from the date of the assessment through~~ December 31, ~~2016 that would impact management’s conclusion.~~2019, and December 31, 2018, respectively, as PSE is a regulated entity.

Cash and Cash Equivalents

Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.

Restricted Cash

Restricted cash amounts are primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities.

Materials and Supplies

Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. ~~Puget Energy and PSE record~~The Company records these items at weighted-average cost.

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)~~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 3,4, "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; the AFUDC debt portion is credited to interest expense, 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 rate authorized by the Washington Commission for natural gas and electric utility plant additions ~~as of July 1, 2013~~through December 18, 2017, was 7.77%. Effective December 19, 2017, with the Washington Commission order, the new AFUDC rate authorized is ~~7.77%~~7.60%.

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.

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. 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 ~~$235.3~~$236.5 million, ~~$234.2~~$239.3 million and ~~$231.7~~$257.1 million for ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission.

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. ~~For GAAP purposes only,~~On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (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 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 Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously ~~non-recorded~~non-recognized amounts will be ~~recorded.~~recognized. Revenues associated

with energy costs under the power cost adjustment (PCA) mechanism and 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, ~~2016~~2019, and ~~2015~~2018, was ~~$9.8~~$8.3 million ~~each year.~~and $8.4 million, respectively.

Self-Insurance

PSE is self-insured for storm damage and certain environmental contamination associated with current operations 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 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. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE ~~records~~to its customers when monetized, used on the ~~benefit~~income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory 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 were also recorded for the regulatory liability. 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 to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as ~~a deferred credit until such time as PSE utilizes~~ the PTCs are monetized. These entries will result in no net income impact. As of December 31, 2019 and 2018, $67.5 million and $84.0 million of PTCs were estimated to be monetized through tax ~~credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers.~~filings, respectively.

Accounting for Derivatives

ASC 815, "Derivatives and Hedging" (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 (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 natural gas related derivatives due to the 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. 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, 2016, Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt.~~ For additional information, see Note 9,10, "Accounting for Derivative Instruments and Hedging 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 10,11, "Fair Value 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.

Leases

PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets.

ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.

PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

(2) New Accounting Pronouncements

~~Revenue Recognition~~Recently Adopted Accounting Guidance

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

In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date.

The Company plans to adopt ASU 2014-09 during the first quarter of fiscal year 2018. Reporting entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. At this time, the Company has not yet selected a transition method; however, it is in the process of completing its analysis and expects to decide in early 2017. Additionally, the Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected, and implement the new revenue recognition guidance. After a substantial evaluation of this standard, the Company does not anticipate significant impacts to its results of operations or on its consolidated financial statements. The Company is still waiting on the resolution of certain industry implementation issues, including contributions in aid of construction (CIAC), to determine the full impact. The Company is anticipating additional disclosures related to the implementation of the new standard.

Lease Accounting

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

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

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

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

These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ~~Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for~~The Company adopted ASU 2016-02 as of January 1, 2019, which resulted in the ~~adoption~~recognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the ~~new standard.~~standard did not have a material impact on the income statement. The ~~Company plans~~financial impact as of the date of adoption was not materially different than what has been disclosed as of December 31, 2019, in Note 9, "Leases", to ~~adopt ASU 2016-02 during~~ the ~~first quarter of fiscal year 2019. At this time, the Company plans to initiate a steering committee and project team to evaluate the impact this standard will have on its results of operations and~~ consolidated financial ~~statements.~~statements included in Item 8 of this report.

~~Derivatives and Hedging~~Internal-Use Software

In ~~March 2016,~~August 2018, the FASB issued ASU ~~2016-06, "Derivatives~~2018-15, "Intangibles—Goodwill and ~~Hedging (Topic 815)~~Other—Internal-Use Software (Subtopic 350-40): ~~Contingent Put and Call Options~~Customer’s Accounting for Implementation Costs Incurred in ~~Debt Instruments"~~a Cloud Computing Arrangement That Is a Service Contract". Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifiesThese amendments align the requirements for ~~assessing whether contingent call~~capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or ~~put options~~obtain internal-use software (and hosting arrangements that ~~can accelerate~~include an internal-use software license). The accounting for the ~~payment~~service element of ~~principal~~a hosting arrangement that is a service contract is not affected by these amendments. While the standard requires that the capitalized implementation costs be reported on ~~debt instruments are clearly~~the balance sheet in the same manner as a prepayment and ~~closely~~the related ~~to their debt hosts. An entity performing~~amortization expense in the ~~assessment under~~same expense line item on the ~~amendment is required to assess~~income statement as the ~~embedded call or put options solely~~expense for the associated cloud computing arrangement, the Company capitalizes implementation costs associated with cloud computing arrangements as a utility plant asset and amortizes the costs in a consistent manner in accordance with ~~the four-step decision sequence.~~FERC Docket Number AI90-1-000.

~~This amendment is~~The amendments in this update are effective for ~~financial statements issued~~public business entities for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017. The Company anticipates the new guidance will not have a significant impact on its financial statements.

~~Statement of Cash Flows~~

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments

made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle. Current GAAP is unclear or does not include specific guidance on the eight cash flow classification issues included in the amendments.

~~This update is effective for financial statements issued for fiscal years beginning after December 15, 2017~~2019, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted, including adoption in any interim period, for all ~~entities upon issuance.~~entities. The amendments in this update should be applied ~~using a retrospective transition method~~either retrospectively or prospectively to ~~each period presented.~~all implementation costs incurred after the date of adoption. The Company ~~plans to adopt ASU 2016-15 during~~adopted this update prospectively

in 2019 for implementation costs incurred in hosting arrangements and application of the ~~first quarter of fiscal year 2018 and is in~~amendment did not have a material impact on the ~~process of evaluating the impact this standard will have on its~~ consolidated ~~statement of cash flows.~~financial statements.

Accounting Standards Issued but Not Yet Adopted

Credit Losses

In ~~November~~June 2016, the FASB issued ASU ~~2016-18, "Statement~~2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of ~~Cash Flows (Topic 230): Restricted Cash"~~Credit Losses on Financial Instruments". The amendments in ~~this~~the update ~~require that~~change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a ~~statement~~current expected loss model, which may result in earlier recognition of ~~cash flows explain~~credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The Company has analyzed its financial instruments within the ~~change during~~scope of the ~~period~~guidance and does not expect a material impact to the consolidated financial statements..

Fair Value Measurement

In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement". The guidance in ASU No. 2018-13 eliminates such disclosures as the ~~total~~amount of ~~cash, cash equivalents,~~ and ~~amounts generally described as restricted cash or restricted cash equivalents.~~reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new ~~standard~~disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, ~~2017,~~2019, and interim periods within those fiscal years, ~~beginning~~with early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or consolidated balance sheet.

Retirement Benefits

In August 2018, the FASB issued ASU 2018-14, "Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans". This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures.

The amendments in this update are effective for fiscal years ending after December 15, ~~2018.~~2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities. The Company ~~plans~~is in the process of evaluating potential impacts of these amendments to ~~adopt ASU 2016-18 during~~Note 13, "Retirement Benefits" to the ~~first quarter~~consolidated financial statements.

(3) Revenue

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


Puget Energy and Puget Sound Energy
(Dollars in Thousands)	Year Ended December 31,
Revenue from Contracts with Customers:	2019		2018
Electric retail	$	2,132,522	$	2,138,008
Natural gas retail	870,457		849,898
Other	308,111		234,187
Total revenue from contracts with customers	3,311,090		3,222,093
Alternative revenue programs	(18,634)		(22,852)
Other non-customer revenue	108,674		147,255
Total operating revenue	$	3,401,130	$	3,346,496

Revenue at PSE is recognized when performance obligations under the terms of ~~fiscal year 2018~~a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services.

Electric and Natural Gas Retail Revenue

Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes.

Other Revenue from Contracts with Customers

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

Electric Transmission and Natural Gas Transportation

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

Biogas

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

Wholesale

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

Other Revenue

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

~~(3)~~

(4) 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.

The net regulatory assets and liabilities at December 31, ~~2016~~2019, and ~~2015~~2018, included the following:


Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)				2019			2018
Storm damage costs electric	1 to 4 years	$	121,894		$	118,331
Chelan PUD contract initiation	11.8 years	83,875			90,964
Environmental remediation	(a)	68,486			76,345
Lower Snake River	17.4 years	62,899			67,021
Decoupling deferrals and interest	Less than 2 years	43,509			65,779
Baker Dam licensing operating and maintenance costs	N/A	56,427			55,607
Deferred Washington Commission AFUDC	30 years	57,553			52,029
Property tax tracker	Less than 2 years	22,442			45,621
Unamortized loss on reacquired debt	2 to 48 years	40,177			42,378
Colstrip 1 & 2 Regulatory Asset	N/A	—			37,674
Energy conservation costs	(a)	25,272			30,701
Get to zero depreciation expense deferral	N/A	22,148			—
Advanced metering infrastructure	(a)	14,845			—
Generation plant major maintenance, excluding Colstrip	3 to 10 years	12,744			15,027
PGA deferral of unrealized losses on derivative instruments	N/A	—			14,739
White River relicensing and other costs	1 year	6,399			12,966
Mint Farm ownership and operating costs	5.3 years	10,318			12,319
PGA receivable	2 years	132,766			9,922
Snoqualmie licensing operating and maintenance costs	N/A	7,442			7,407
Colstrip major maintenance	0.0 years	2,929			6,841
PCA mechanism	N/A	41,745			4,735
Colstrip common property	4.4 years	3,188			3,903
Ferndale	0.0 years	—			3,316
Various other regulatory assets	(a)	10,474			14,583
Total PSE regulatory assets		$	847,532		$	788,208
Deferred income taxes (d)	N/A	(946,936)			(976,582)
Cost of removal	(b)	(469,922)			(424,727)
Treasury grants	18 years	(101,981)			(168,884)
Production tax credits	(c)	(85,323)			(93,616)
Gain on Sale Shuffleton	N/A	(12,483)			—
Microsoft special contract regulatory liability	N/A	(12,661)			—
Repurposed production tax credits	N/A	(23,171)			—
Accumulated provision for rate refunds	N/A	—			(34,579)


Total decoupling liability	Less than 2 years	(8,500)			(13,758)

Various other regulatory liabilities	(a)	(15,573)			(10,316)
Total PSE regulatory liabilities		(1,676,550)			(1,722,462)
PSE net regulatory assets (liabilities)		$	(829,018)		$	(934,254)

__________________

^(a)Amortization periods vary depending on timing of underlying transactions.

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

^(c)Amortize as PTCs are utilized by PSE on its tax return.

^(d)For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.

Puget Sound Energy Remaining Amortization Period December 31,
(Dollars in Thousands) 2016 2015
Colstrip Regulatory Asset (a) $ 176,804
$ —
Storm damage costs electric 1 to 2 years 122,709
125,777
Chelan PUD contract initiation 14.8 years 105,140
112,228
Decoupling deferrals and interest 156,408

104,150

Decoupling 24-month revenue reserve (20,847 ) (9,980 )
Total decoupling asset Less than 2 years 135,561
94,170
Lower Snake River 1 to 20.3 years 74,862
79,599
Deferred income taxes (a) 71,517
72,694
Environmental remediation (a) 74,557
66,887
Baker Dam licensing operating and maintenance costs 42 years 61,453
63,394
PGA deferral of unrealized losses on derivative instruments (a) —
60,889
Deferred Washington Commission AFUDC 35 years 51,404
52,197
Unamortized loss on reacquired debt 1 to 30 years 42,196
44,984
Property tax tracker Less than 2 years 41,949
40,353
Energy conservation costs 1 to 2 years 41,027
36,646
White River relicensing and other costs 15.9 years 21,627
23,054
Mint Farm ownership and operating costs 8.3 years 16,319
18,320
Ferndale 2.8 years 11,274
15,253
Electron unrecovered loss 2 years 7,178
10,569
Snoqualmie licensing operating and maintenance costs 28 years 8,018
7,980
Colstrip common property (a) 5,334
6,049
Colstrip major maintenance 2 years 6,589
5,897
Investment in Bonneville Exchange power contract 1 year 1,763
5,290
Snoqualmie 1.8 years 3,251
5,024
PCA mechanism (a) 4,531
—
PGA receivable 1 year 2,785
—
Various other regulatory assets Varies 25,337
24,248
Total PSE regulatory assets 1,113,185
971,502
Cost of removal (b) (369,300 ) (347,472 )
Treasury grants 3 to 42 years (133,709 ) (157,102 )
Production tax credits (c) (93,616 ) (93,616 )
Decoupling ROR excess earnings (13,300 ) (25,483 )
Decoupling deferrals and interest (16,448 ) —

Total decoupling liability Less than 2 years (29,748 ) (25,483 )
PGA payable 1 year —
(12,589 )
Summit purchase option buy-out 3.8 years (6,038 ) (7,612 )
Deferral of treasury grant amortization Less than 3 years (3,920 ) (6,058 )
PGA deferral of unrealized gains on derivative instruments (a) (7,517 ) —
Lower Snake River interest due Less than 2 years (4,189 ) —
Various other regulatory liabilities Up to 4 years (5,259 ) (13,751 )
Total PSE regulatory liabilities (653,296 ) (663,683 )
PSE net regulatory assets (liabilities) $ 459,889
$ 307,819


Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2019		2018
Total PSE regulatory assets	(a)	$	847,532	$	788,208
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	6 to 33 years	14,146		16,693

Total Puget Energy regulatory assets		861,678		804,901
Total PSE regulatory liabilities	(a)	(1,676,550)		(1,722,462)
Puget Energy acquisition adjustments:
Deferred income taxes		757		608
Regulatory liabilities related to power contracts	6 to 33 years	(156,597)		(162,711)
Various other regulatory liabilities	Varies	(1,265)		(1,323)
Total Puget Energy regulatory liabilities		(1,833,655)		(1,885,888)
Puget Energy net regulatory asset (liabilities)		$	(971,977)	$	(1,080,987)

~~_______________~~


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


^(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.~~

____________________

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

Puget Energy Remaining Amortization Period December 31,
(Dollars in Thousands) 2016 2015
Total PSE regulatory assets (a) $ 1,113,185
$ 971,502
Puget Energy acquisition adjustments:

Regulatory assets related to power contracts 1 to 21 years 22,613
26,223
Various other regulatory assets Varies 517
549
Total Puget Energy regulatory assets 1,136,315
998,274
Total PSE regulatory liabilities (a) (653,296 ) (663,683 )
Puget Energy acquisition adjustments:

Regulatory liabilities related to power contracts 1 to 36 years (275,061 ) (325,788 )
Various other regulatory liabilities Varies (1,326 ) (1,347 )
Total Puget Energy regulatory liabilities (929,683 ) (990,818 )
Puget Energy net regulatory asset (liabilities) $ 206,632
$ 7,456

~~_______________~~


^(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 ~~$369.3~~$469.9 million and ~~$347.5~~$424.7 million in ~~2016~~2019 and ~~2015~~,2018, 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~~

PSE filed a ~~settlement agreement~~GRC with the Washington Commission on ~~March 22, 2013. The agreement was intended~~June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to ~~settle all issues regarding decoupling,~~the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a ~~power purchase agreement with TransAlta Centralia~~portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and ~~the~~Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) ~~which is limited~~as discussed below, PSE requested in ~~scope and rate impact, includes~~its GRC to pass back the ~~property tax tracker, and is intended to establish baseline rates on which the decoupling mechanisms are to operate. The Washington Commission placed the ERF and decoupling filings under~~amounts over four years. On September 17, 2019, PSE filed a ~~common procedural schedule.~~

~~On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF~~supplemental 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~~GRC, which provided updates as discussed in our original filing, ~~with a small change to its cost of capital from 7.80% to7.77% to update long term debt costs~~but did not impact the requested overall electric and ~~a capital structure that included 48.0% common equity with a~~natural gas rate increases, return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorizedor overall rate of ~~return. In addition,~~return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate ~~plan (K-Factor)~~of return to 7.48%.The requested rate increase ~~allowed decoupling revenue per customer~~ for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the ~~recovery of delivery system costs~~decrease in return on equity led to ~~subsequently increase by 3.0% for~~a reduction in the electric ~~customers~~rate increase of only $1.5 million and ~~2.2% for~~did not have an impact on the natural gas ~~customers on~~rate increase.

In January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was filed on January 13, 2017. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers.

~~General Rate Case Filing~~

~~On January 13,~~ 2017, PSE filed its GRC with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for 2 new mechanisms to address regulatory lag. The Washington Commission ~~which proposed~~entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017, and new rates became effective December 19, 2017. The settlement agreement provided for a weighted cost of capital of ~~7.74%~~7.6%, or ~~6.69%~~6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of ~~9.8%~~9.5%. The ~~requested~~settlement also resulted in a combined electric tariff ~~changes would result~~change that resulted in a net increase of ~~$86.3~~$20.2 million, or ~~4.1%. The requested~~0.9%, annually, and a combined natural gas tariff

~~changes would result~~ change that resulted in a net decrease of ~~$22.3~~$35.5 million, or ~~2.4%.~~ 3.8%, annually.

The ~~filing was subsequently suspended, which means that~~2017 GRC also re-purposed the ~~final rates granted in the proceeding will go into effect no later than December 13, 2017.~~

~~PSE’s GRC filing included the required plan~~benefit of hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and ~~2 closures, see Item 3, "Legal Proceedings"~~2.

Expedited Rate Filing Rate Adjustment

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

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million for natural gas and 0 rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.

The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019:

1)excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019,

2)the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and

3)the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF.

The agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in ~~Item 8~~the test year of the filing. The agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s 2019 GRC. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49% . On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

Washington Commission Tax Deferral Filing

The TCJA was signed into law in December 2017. As a result of this ~~report.~~change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, ~~PSE’s filing contains requests~~on March 30, 2018, PSE filed for ~~two new mechanisms to address regulatory lag. PSE has requested procedures~~a rate change 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 ~~CRM similar to its existing~~and natural gas ~~CRM~~customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4%, for electric and $23.6 million, or 2.7%, for natural gas and became effective May 1, 2018, by operation of law.

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

As a result of the Washington Commission's final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2019, through February 28, 2019, was addressed in PSE’s GRC, which ~~would allow~~was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE ~~to obtain accelerated cost recovery on specified electric reliability projects.~~pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019.

Decoupling Filings

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms ~~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 mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues ~~will be~~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 over a 12-month period beginning~~during the following ~~May.~~May to April time period.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will ~~end on December 31, 2017 unless the continuation of the requested~~be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism ~~is approved in PSE's 2017 GRC which PSE filed on January 13, 2017. Decoupling over~~over- and ~~under~~under- collections will still be collectible or refundable after ~~December 31, 2017,~~this effective date even if the decoupling mechanism is not extended.

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

On December 31, 2019, PSE ~~requests~~performed an analysis to ~~change rates under its~~determine if electric and natural gas decoupling ~~mechanisms:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
Electric:
May 1, 2016 1.0% $20.8
May 1, 2015 2.6 53.8
May 1, 2014 0.5 10.6
Natural Gas:
May 1, 2016 2.8% $25.4
May 1, 2015 2.1 22.0
May 1, 2014 (0.1) (1.0)

~~As part~~revenue deferrals would be collected from customers within 24 months of the ~~April 22, 2015 filing,~~annual period, per ASC 980. If not, for GAAP purposes only, PSE ~~requested~~would need to ~~change~~record a reserve against the ~~methodology~~decoupling revenue and regulatory asset balance. Once the reserve is probable of ~~how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that~~collection within 24 months from the ~~amortization of prior years’ accumulated decoupling deferrals were not included in the calculation~~end of the ~~current year~~annual period, the reserve can be recognized as decoupling ~~deferrals.~~revenue. The ~~effect of the methodology change was a reduction of approximately $12.0 million of previously recognized revenue from May through December of 2014.~~

In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filinganalysis indicated that ~~will be made on March 31, 2017.~~

~~PSE recorded the following reductions in decoupling deferrals to the~~ electric and natural gas ~~rate increases above:~~

Effective Date
Reduction in Rate Increases due to Excess Earnings
(Dollars in Millions)
Electric:
2016 (estimated) $11.2
2015 16.3
2014 3.4
Natural Gas:
2016 (estimated) $2.1
2015 9.2
2014 —

~~As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows:~~

Effective Date Accrued Through
Deferrals not Included in Annual Rate Increases
(Dollars in Millions)
Electric:
2015 $—
2014 1.9
Natural Gas:
2015 $28.7
2014 8.2

~~Existing deferrals may~~deferred revenue will be ~~included in customer rates beginning in May 2018, subject to subsequent application~~collected within 24 months of the ~~earnings test and the 3.0% cap on~~annual period; therefore, no adjustment was booked to 2019 decoupling ~~related rate increases.~~

~~Electric Regulation and Rates~~

~~Storm Damage Deferral Accounting~~

revenue. The ~~Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess~~previously unrecognized decoupling deferrals of ~~$8.0 million annually may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2016 and 2015, PSE incurred $22.0~~$0.8 million and ~~$33.6~~$20.8 million ~~respectively,~~at December 31, 2018, and December 31, 2016, were recognized as decoupling revenue in ~~storm-related electric transmission~~the year ended December 31, 2019, and ~~distribution system restoration costs, of which $12.4 million was deferred in 2016 and $22.4 million was deferred in 2015.~~December 31, 2017, respectively.

Power Cost Adjustment Mechanism

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

~~The~~Effective January 1, 2017, the following graduated scale ~~that~~is used in the PCA mechanism:


	Company’s Share									Customers' Share
Annual Power Cost Variability	Over		Under				Over			Under
Over or Under Collected by up to $17 million	100	%	100	%	—	%		—	%
Over or Under Collected by between $17 million - $40 million	35		50		65			50
Over or Under Collected beyond $40 + million	10		10		90			90

In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested was ~~applicable~~January 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC. In November 2016, ~~was as follows:~~

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

~~On August 7, 2015,~~ the Washington Commission issued ~~an order~~Order No. 01 approving PSE’s accounting petition. With the ~~settlement proposing changes to~~final determination in PSE’s GRC, this deferral ceased with the ~~PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale:~~rate effective date of December 19, 2017.

Annual Power Cost Variability Company's Share Customers' Share
Over or Under Collection: Over Under Over Under
Over or Under Collected by up to $17 million 100% 100% —% —%
Over or Under Collected by between $17 million - $40 million 35 50 65 50
Over or Under Collected beyond $40 + million 10 10 90 90

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

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

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

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

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

~~PSE had an annual PCA receivable during~~For the year ended December 31, ~~2016, due~~2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to ~~under recovering~~customers and $1.0 million of ~~power costs of which no amounts were apportioned to customers.~~interest was accrued on the deferred customer balance. This compares to an ~~annual PCA receivable~~under recovery of ~~$8.7~~allowable costs of $3.5 million for the year ended December 31, ~~2015~~2018, of which no0 amounts were apportioned to ~~customers. The change was driven~~customers and accrued $0.2 million of interest on the total deferred customer balance. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a ~~decrease in actual costs.~~

~~Federal Incentive Tracker Tariff~~

~~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:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates from prior year
Total credit to be passed back to eligible customers
(Dollars in Millions)
January 1, 2017, proposed 0.3% $(51.7)
January 1, 2016 (0.2) (57.3)
January 1, 2015 (0.2) (55.2)
January 1, 2014 (0.3) (58.5)

~~Power Cost Only Rate Case and Update Compliance Filing~~

~~The following table sets forth PCORC and update compliance filing 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, 2016 (1.7)% $(37.3)
December 1, 2014 (0.9) (19.4)

~~Electric Property Tax Tracker Mechanism~~

~~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, 2016 0.3% $5.7
May 1, 2015 0.3 6.5
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, 2017, proposed 0.7% $16.5
May 1, 2016 (0.5) (11.7)
May 1, 2015 0.2 4.2
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 millionnarrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a ~~pre-tax gain of approximately $60.0 million. A final order was rendered on September 11, 2014~~transmission line, which ~~authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was booked~~contributed to a ~~regulatory liability account~~liquidity crisis at Mid-C and resulted in ~~other current liabilities~~high market power prices; and ~~accrued interest at PSE's after-tax rate~~(iv) The relative prices of ~~return. PSE paid this amount to customers through a bill credit in~~natural gas and power, which reduced the ~~month~~supply of ~~December 2014.~~natural gas-fired generation and increased the demand for market power, increasing prices.

~~Natural Gas Regulation and Rates~~

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

Purchased Gas Adjustment

For the year ended December 31, 2018, PSE had a beginning PGA payable balance of $16.1 million, incurred actual natural gas costs of $319.3 million, of which $292.0 million was recovered through rates. The ~~following table sets forth~~difference between actual and allowed costs, less interest $1.3 million, resulted in a PGA receivable of $9.9 million. For the year ended December 31, 2019, PSE had incurred actual natural gas costs of $406.2 million, of which $289.9 million was recovered through rates. The difference between actual and allowed costs, plus interest of $6.6 million, resulted in a PGA receivable of $132.8 million.

On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate ~~adjustments~~change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The amortization period will be from May 2019 through April 2020.

Get to Zero Depreciation Deferral

On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, 2019, PSE deferred $21.7 million of depreciation expense for GTZ. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. For the year ended December 31, 2019, PSE deferred $0.5 million of carrying charges on the deferral. The GTZ accounting petition was consolidated with

PSE’s 2019 GRC and is currently being reviewed by the Washington ~~Commission~~Commission. If authorized, both the GTZ depreciation and ~~the corresponding impact on PSE’s revenue based~~interest on the ~~effective dates:~~deferral will be begin amortizing over three years in May 2020

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2016 (0.4)% $(4.1)
November 1, 2015 (17.4) (185.9)
November 1, 2014 2.5 23.3

~~Cost Recovery Mechanism~~Storm Damage Deferral Accounting

The ~~following table sets forth CRM rate adjustments approved by the~~ Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the ~~corresponding impact on PSE’s revenue based on~~annual cost threshold may be deferred for qualifying storm damage costs that meet the ~~effective dates:~~

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2016 0.6% $5.6
November 1, 2015 0.5 5.3
November 1, 2014 0.2 2.3

~~Natural Gas Property Tax Tracker Mechanism~~

~~The following table sets forth property tax tracker mechanism rate adjustments approved by~~modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2019, PSE incurred $39.3 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $0.4 million and $28.5 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $25.4 million incurred in storm-related electric transmission and distribution system restoration costs for the year ended December 31, 2018, of which the Company deferred $3.3 million and $11.9 million as regulatory assets related to storms that occurred in 2017 and 2018, respectively. 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 ~~corresponding impact on PSE’s revenue based on~~total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the ~~effective dates:~~$10.0 million annual cost threshold.

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2016 0.4% $3.5
June 1, 2015 (0.2) (2.3)
May 1, 2014 0.6 5.6

~~Natural Gas Conservation Rider~~

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

Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2017, proposed (0.1)% (1.0)
May 1, 2016 0.3 2.9
May 1, 2015 0.2 2.3

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 natural gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008.

In 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 ~~$38.0~~$41.8 million for natural gas and ~~$6.2~~$8.7 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, ~~2016,~~2019, the Company’s share of future remediation costs is estimated to be approximately ~~$24.9~~$31.6 million. The Company's deferred electric environmental costs are ~~$13.8 million, $14.0~~$13.7 million and ~~$13.4~~$14.1 million at December 31, ~~2016, 2015~~2019 and ~~2014,~~2018, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are ~~$60.7 million, $52.9~~$54.8 million and ~~$52.6~~$62.2 million at December 31, ~~2016, 2015~~2019 and ~~2014,~~2018, respectively, net of insurance proceeds. In the ~~pending~~2017 GRC, the Company ~~has requested to ratebase~~had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and ~~third party recoveries.~~inclusion in rates, effective December 19, 2017.

~~(4)~~(5) 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, ~~2016,~~2019, approximately ~~$532.9~~$914.2 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.

Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was ~~47.9%~~48.4% at December 31, ~~2016,~~2019, and the EBITDA to interest expense was ~~5.2~~5.3 to 1.0 for the twelve months ended December 31, ~~2016.~~

2019.

such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was ~~3.5~~3.6 to 1.0 for the twelve months ended December 31, ~~2016.~~2019.

At December 31, ~~2016,~~2019, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

~~(5)~~(6) Utility Plant

The following table presents electric, natural gas and common utility plant classified by account:


		Puget Energy						Puget Sound Energy
Utility Plant	Estimated Useful Life	December 31,						December 31,
(Dollars in Thousands)	(Years)	2019		2018		2019		2018
Distribution plant	20-65	$	6,602,934	$	6,122,739	$	8,185,700	$	7,722,024
Production plant	12-90	3,066,792		3,099,805		3,743,493		3,974,250
Transmission plant	43-75	1,463,288		1,442,854		1,571,186		1,550,950
General plant	5-75	698,275		682,976		731,279		718,105
Intangible plant (including capitalized software)¹	3-50	735,826		662,328		726,383		652,942
Plant acquisition adjustment	N/A	242,826		242,826		282,792		282,792
Underground storage	25-60	37,511		35,404		50,963		48,874
Liquefied natural gas storage	25-60	12,628		12,628		14,498		14,498
Plant held for future use	N/A	46,233		39,384		46,385		39,536
Recoverable Cushion Gas	N/A	8,655		8,655		8,655		8,655
Plant not classified	N/A	316,923		239,857		316,923		239,857
Finance leases, net of accumulated amortization²	N/A	1,488		1,315		1,488		1,315
Less: accumulated provision for depreciation		(3,236,240)		(2,832,321)		(5,682,606)		(5,495,348)
Subtotal		$	9,997,139	$	9,758,450	$	9,997,139	$	9,758,450
Construction work in progress		591,199		550,466		591,199		550,466
Net utility plant		$	10,588,338	$	10,308,916	$	10,588,338	$	10,308,916

Puget Energy Puget Sound Energy
Utility Plant
Estimated
Useful Life
At December 31, At December 31,
(Dollars in Thousands) (Years) 2016 2015 2016 2015
Distribution plant 10-50 $ 5,287,542
$ 5,007,077
$ 6,922,176
$ 6,657,597
Production plant 25-125 3,007,546
3,028,481
3,910,129
3,950,231
Transmission plant 45-65 1,307,687
1,236,823
1,420,334
1,351,216
General plant 5-35 541,424
491,845
611,237
563,850
Intangible plant (including capitalized software) 3-50 347,697
305,705
338,327
294,380
Plant acquisition adjustment 2-22 242,826
242,826
282,792
282,792
Underground storage 25-60 30,695
28,914
44,206
42,545
Liquefied natural gas storage 25-45 12,628
12,628
14,498
14,498
Plant held for future use NA 52,484
55,890
52,636
56,042
Recoverable Cushion Gas NA 8,655
8,655
8,655
8,655
Plant not classified 1-125 159,345
65,892
159,345
65,892
Grant NA (99,100 ) (102,379 ) (99,100 ) (102,379 )
Capital leases, net of accumulated amortization¹
2 645
378
645
378
Less: accumulated provision for depreciation (2,161,796 ) (1,878,868 ) (4,927,602 ) (4,681,830 )
Subtotal $ 8,738,278
$ 8,503,867
$ 8,738,278
$ 8,503,867
Construction work in progress NA 420,278
408,795
420,278
408,795
Net utility plant $ 9,158,556
$ 8,912,662
$ 9,158,556
$ 8,912,662
_______________________

~~_______________~~1.Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively.


¹	~~Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and~~ ~~$32.3 million~~ ~~in 2015.~~

2.At December 31, 2019, and 2018, accumulated amortization of capital leases at Puget Energy and PSE was $1.0 million and $1.3 million, respectively.

Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following ~~table indicates~~tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, ~~2016.~~2019. These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income.


Puget Energy
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation

Colstrip Units 3 & 4	Coal	25.00%	$	323,100	$	—	$	(138,827)
Frederickson 1	Natural Gas	49.85	61,820		—		(10,995)
Jackson Prairie	Natural Gas	33.34	36,837		119		(8,452)
Tacoma LNG	Natural Gas	various	—		362,684		—


Puget Sound Energy													Puget Sound Energy
Jointly Owned Generating Plants (Dollars in Thousands)													Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Construction Work in Progress		Accumulated Depreciation

			Puget Energy’s Share					Puget Sound Energy’s Share
Jointly Owned Generating Plants (Dollars in Thousands)	Energy Source (Fuel)	Company’s Ownership Share	Plant in Service at Cost		Accumulated Depreciation			Plant in Service at Cost		Accumulated Depreciation
Colstrip Units 1 & 2	Coal	50%	$	70,717	$	(22,284	)	$	204,334	$	(155,902	)
Colstrip Units 3 & 4	Coal	25%	307,383		(40,343		)	575,902		(308,861		)	Colstrip Units 3 & 4	Coal	25.00%	$	582,372	$	—	$	(398,099)
Colstrip Units 1 – 4 Common Facilities	Coal	various	83		(27		)	252		(196		)
Frederickson 1	Natural Gas	49.85%	61,780		(9,779		)	70,729		(18,728		)	Frederickson 1	Natural Gas	49.85	67,888		—		(17,063)
Jackson Prairie	Natural Gas Storage	33.34%	30,021		(5,544		)	44,206		(19,730		)	Jackson Prairie	Natural Gas	33.34	50,963		119		(22,578)
Tacoma LNG													Tacoma LNG	Natural Gas	various	—		162,820		—

In June 2019, Talen, the plant operator of Colstrip 1&2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2019, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs.

Asset Retirement Obligation

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

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

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

During the third quarter 2016, PSE entered into two new legal agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4.

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

~~During~~For the ~~first quarter 2016,~~twelve months ended December 31, 2019, the Company ~~updated its~~reviewed the estimated ~~decommissioning~~remediation costs at Colstrip and increased the Colstrip ARO liability by $4.2 million for Colstrip Units 1 and 2 and $0.5 million for Colstrip Units 3 and 4. The 2019 increase to the Colstrip ARO liability are primarily due to accelerated timing of activities due to the ~~timing~~closure of ~~its~~Colstrip Units 1 and 2 at the end of 2019. For the twelve months ended December 31, 2018, the company reduced the Colstrip ARO liability by $11.0 million for ~~Lower Snake River~~Colstrip Units 1 and ~~Hopkins Ridge wind generation sites~~2, and increased $1.8 million for Colstrip Units 3 and 4. The 2018 change to the Colstrip ARO liability is primarily based on the plant site remedy report approved by the Montana Department of Environmental Quality. For the twelve months ended December 31, 2019 and 2018, the Company also recorded the Colstrip relief of liability of $12.4 million and $4.8 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of ~~$19.7 million.~~

~~The following table describes the changes to the Company’s ARO liability~~$3.0 million and $2.7 million for PSE and $4.3 million and $1.7 million for Puget LNG as of December 31, ~~2016~~2019 and ~~2015:~~December 31, 2018, respectively. The 2019 increase to the Tacoma LNG facility ARO liability is primarily due to continued construction of the plant.


	At December 31,
Puget Energy and Puget Sound Energy							Puget Energy and Puget Sound Energy	December 31,
(Dollars in Thousands)	2016			2015			(Dollars in Thousands)	2019		2018
Asset retirement obligation at beginning of period	$	85,028		$	48,909
Asset retirement obligation at beginning of the period							Asset retirement obligation at beginning of the period	$	182,203	$	191,176
New asset retirement obligation recognized in the period	—			34,534			New asset retirement obligation recognized in the period	—		501
Liability adjustment in the period	(411		)	(3,628		)
Relief of liability							Relief of liability	(12,449)		(4,750)
Revisions in estimated cash flows	113,081			3,403			Revisions in estimated cash flows	5,922		(10,512)
Accretion expense	2,647			1,810			Accretion expense	5,677		5,788
Asset retirement obligation at end of period	$	200,345		$	85,028
Asset retirement obligation at end of period¹							Asset retirement obligation at end of period¹	$	181,353	$	182,203

___________________

1.Asset retirement obligations include $4.3 million and $1.7 million for Puget LNG held only at PE as of December 31, 2019, and 2018, respectively.

The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, ~~2016 due to:~~2019:

•A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated;

•An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated;

•An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated;

•A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated;

•An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and

•A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

~~(6)~~

(7) Long-Term Debt

The following table presents outstanding long-term debt principal amounts and due dates as of 2019 and 2018:


(Dollars in Thousands)					December 31,
Series	Type	Due	2019		2018
Puget Sound Energy:
5.500%	Promissory Note¹	2020	$	—	$	2,412
7.150%	First Mortgage Bond	2025	15,000		15,000
7.200%	First Mortgage Bond	2025	2,000		2,000
7.020%	Senior Secured Note	2027	300,000		300,000
7.000%	Senior Secured Note	2029	100,000		100,000
3.900%	Pollution Control Bond	2031	138,460		138,460
4.000%	Pollution Control Bond	2031	23,400		23,400
5.483%	Senior Secured Note	2035	250,000		250,000
6.724%	Senior Secured Note	2036	250,000		250,000
6.274%	Senior Secured Note	2037	300,000		300,000
5.757%	Senior Secured Note	2039	350,000		350,000
5.795%	Senior Secured Note	2040	325,000		325,000
5.764%	Senior Secured Note	2040	250,000		250,000
4.434%	Senior Secured Note	2041	250,000		250,000
5.638%	Senior Secured Note	2041	300,000		300,000
4.300%	Senior Secured Note	2045	425,000		425,000
4.223%	Senior Secured Note	2048	600,000		600,000
3.250%	Senior Secured Note	2049	450,000		—
4.700%	Senior Secured Note	2051	45,000		45,000

*	Debt discount, issuance cost and other	*	(37,718)		(31,412)
Total PSE long-term debt							4,336,142		3,894,860
Puget Energy:
*	Fair value adjustment of PSE long-term debt	*	(173,865)		(182,372)
*	Revolving Credit Agreement	2023	24,100		11,900
*	Term Loan Agreement	2021	174,000		150,000
*	Term Loan Agreement	2022	210,000		—
6.500%	Senior Secured Note²	2020	—		450,000
6.000%	Senior Secured Note	2021	500,000		500,000
5.625%	Senior Secured Note	2022	450,000		450,000
3.650%	Senior Secured Note	2025	400,000		400,000
*	Debt discount, issuance cost and other	*	(52)		(1,897)
Total Puget Energy long-term debt							$	5,920,325	$	5,672,491

___________________

*Not Applicable.

^1.5.500% Promissory Note in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt as of August 12, 2019.

^2.6.500% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of December ~~31, 2016 and 2015:~~14,2019.

(Dollars in Thousands) At December 31,
Series Type Due 2016 2015
Puget Sound Energy:
5.500% Promissory Note 2017 $ 2,412
$ 2,412
6.740% Senior Secured Note 2018 200,000
200,000
7.150% First Mortgage Bond 2025 15,000
15,000
7.200% First Mortgage Bond 2025 2,000
2,000
7.020% Senior Secured Note 2027 300,000
300,000
7.000% Senior Secured Note 2029 100,000
100,000
3.900% Pollution Control Bond 2031 138,460
138,460
4.000% Pollution Control Bond 2031 23,400
23,400
5.483% Senior Secured Note 2035 250,000
250,000
6.724% Senior Secured Note 2036 250,000
250,000
6.274% Senior Secured Note 2037 300,000
300,000
5.757% Senior Secured Note 2039 350,000
350,000
5.795% Senior Secured Note 2040 325,000
325,000
5.764% Senior Secured Note 2040 250,000
250,000
4.434% Senior Secured Note 2041 250,000
250,000
5.638% Senior Secured Note 2041 300,000
300,000
4.300% Senior Secured Note 2045 425,000
425,000
4.700% Senior Secured Note 2051 45,000
45,000
6.974% Junior Subordinated Note 2067 250,000
250,000
* Debt discount, issuance cost and other * (28,974 ) (31,910 )
Total PSE long-term debt 3,747,298
3,744,362
Puget Energy:
* Fair value adjustment of PSE long-term debt * (199,436 ) (207,977 )
* Revolving Credit Agreement 2018 12,480
—
6.500% Senior Secured Note 2020 450,000
450,000
6.000% Senior Secured Note 2021 500,000
500,000
5.625% Senior Secured Note 2022 450,000
450,000
3.650% Senior Secured Note 2025 400,000
400,000
* Debt discount, issuance cost and other * (6,269 ) (8,867 )
Total Puget Energy long-term debt $ 5,354,073
$ 5,327,518

~~_______________~~


*	~~Not Applicable.~~

PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, ~~2016~~,2019, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025.

Puget Energy Long-Term Debt

On October 1, 2018, Puget Energy entered into a $150.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or at London Interbank Offered Rate (LIBOR) plus a spread based on credit rating. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.

In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate.

On September 26, 2019, Puget Energy entered into a separate $210.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program.

Puget Sound Energy Long-Term Debt

On August 2, 2019, PSE ~~has in effect~~filed a new shelf registration statement ~~("the existing shelf")~~ under which it may issue, ~~as of the date of this report,~~ up to ~~$800.0 million~~$1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration. The ~~existing~~ shelf registration will expire in ~~November 2019.~~August 2022.

Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, ~~2016~~,2019, the earnings available for interest exceeded the required amount.

On ~~May 26, 2015,~~March 5, 2018, PSE commenced a tender offer and related consent solicitation to purchase any and all of the outstanding $250.0 million 6.974% Series A Enhanced Junior Subordinated Notes due June 1, 2067. Holders of the notes received $1,005 per $1,000 principal amount of notes plus accrued and unpaid interest for notes tendered and accepted by the early tender payment deadline of March 16, 2018. Holders of notes tendered after the early tender payment deadline, but prior to the tender offer expiration on April 2, 2018, were to receive the tender offer consideration of $975 per $1,000 of principal amount of the notes plus accrued but unpaid interest. A total of $193.4 million in principal amount of notes were tendered by the early payment deadline and no notes were tendered after the early payment deadline. On March 20, 2018, $194.9 million was paid to the holders of the tendered notes. This amount included the principal, early tender consideration and accrued interest up to, but not including March 20, 2018.

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

On March 28, 2018, PSE issued ~~$425.0~~a notice of redemption, effective April 27, 2018, for the remaining $56.6 million principal amount of the 6.974% Series A Enhanced Junior Subordinated Notes. The notes were redeemed at a price equal to 100% of their principal amount plus accrued and unpaid interest up to, but excluding the redemption date.

On June 4, 2018, PSE issued $600.0 million of 30-year Senior Notes under its senior ~~notes secured by first mortgage bonds. The notes mature in May 2045 and have~~note indenture at an interest rate of ~~4.30%, which is payable semi-annually in May and November. Net~~4.223% with a maturity date of June 15, 2048. The proceeds offrom the issuance were used to ~~fund~~pay the ~~early retirement, including~~principal and accrued interest on the Company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and ~~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.~~other general corporate expenses.

100

~~Puget Energy Long-Term Debt~~

~~In May 2015, Puget Energy~~On August 30, 2019, PSE issued ~~$400.0~~$450.0 million of senior ~~secured~~ notes ~~in a private placement. The notes mature in May 2025 and have~~at an interest rate of ~~3.65%, which is payable~~3.250%. The notes pay interest semi-annually ~~in May~~ and ~~November. Net proceeds~~are due to mature on September 15, 2049. Proceeds from the sale of the ~~issuance~~notes were used to repay outstanding ~~Puget Energy indebtedness and to fund a special dividend to shareholders. In November 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in~~short term debt under the ~~May 2015 private placement for registered notes of the same amount.~~Company’s commercial paper program.

Long-Term Debt Maturities

The principal amounts of long-term debt maturities for the next five years and thereafter are as follows:


(Dollars in Thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Maturities of:
PSE	$	2,412	$	—	$	—	$	—	$	—	$	4,373,860	$	4,376,272
Puget Energy	450,000		674,000		660,000		24,100		—		400,000		2,208,100
Total long-term debt	$	452,412	$	674,000	$	660,000	$	24,100	$	—	$	4,773,860	$	6,584,372

(Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total
Maturities of:
PSE long-term debt $ 2,412
$ 200,000
$ —
$ —
$ —
$ 3,573,860
$ 3,776,272
Puget Energy long-term debt —
12,480
—
450,000
500,000
850,000
1,812,480
Puget Energy long-term debt $ 2,412
$ 212,480
$ —
$ 450,000
$ 500,000
$ 4,423,860
$ 5,588,752

~~(7)~~(8) Liquidity Facilities and Other Financing Arrangements

As of December 31, ~~2016~~2019, and ~~2015,~~2018, PSE had ~~$245.8~~$176.0 million and ~~$159.0~~$379.3 million in short-term debt outstanding, ~~respectively, exclusive of the demand promissory note with Puget Energy.~~respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit ~~facilities~~facility are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during ~~2016~~2019 and ~~2015~~2018 was ~~3.21%~~3.4% and ~~4.24%~~3.4%, respectively. As of December 31, ~~2016,~~2019, PSE and Puget Energy had several committed credit facilities that are described below.

Puget Sound Energy

Credit ~~Facilities~~Facility

In October 2017, PSE ~~has~~entered into a new $800.0 million credit facility which consolidates the two ~~unsecured revolving credit~~previous facilities ~~which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of~~into a ~~$650.0 million revolving liquidity facility (which includes a liquidity~~single, smaller facility. All other features including fees, interest rate options, letter of credit, ~~facility~~same day swingline borrowings, financial covenant and ~~a swingline facility) to be used for general corporate purposes, including a backstop to~~accordion feature remain substantially the ~~Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of~~same. The 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~~facility also ~~have~~has an ~~accordion~~expansion feature which, upon the banks' approval, would increase the total size of ~~these facilities~~the facility to ~~$1.5~~$1.4 billion.

~~In April 2014,~~ On September 25, 2019, with no changes to the ~~Company completed a one-year extension on both~~size, terms or conditions, the maturity of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committedunsecured revolving credit facility was extended for one year. The facility now matures in ~~2013.~~ October 2023.

The credit ~~agreements are~~agreement is syndicated among numerous lenders and ~~contain~~contains usual and customary affirmative and negative covenants that, among other things, ~~place~~places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit ~~agreements~~agreement also ~~contain~~contains 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, ~~2016,~~2019, PSE was in compliance with all applicable covenant ratios.

The credit ~~agreements provide~~agreement provides PSE with the ability to borrow at different interest rate options. The credit ~~agreements allow~~agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the ~~London Interbank Offered Rate (LIBOR)~~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.~~facility. The

spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is ~~1.75%~~1.25% and the commitment fee is ~~0.275%~~0.175%.

As of December 31, ~~2016,~~2019, no amounts were drawn and outstanding under ~~either~~ PSE's ~~$650.0 million facility or PSE's $350.0 million energy hedging~~credit facility. No letters of credit were outstanding ~~under either facility,~~ and ~~$245.8~~$176.0 million was outstanding under the commercial paper program. Outside of the credit ~~agreements,~~agreement, PSE had a ~~$3.5~~$2.8 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

101

facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, ~~2016,~~2019, there was no outstanding balance under the Note.

Puget Energy

Credit Facility

~~At December 31, 2016,~~In October 2017, Puget Energy ~~maintained an~~entered into a new $800.0 million ~~revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured~~ credit facility ~~extending~~to replace the ~~maturity from February 2017 to April 2018, updating the fee structure, eliminating a~~existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and ~~updating~~expansion feature remain substantially the same. On September 25, 2019, with no changes to the size, terms or ~~clarifying~~conditions, the ~~definitions~~maturity of ~~other terms~~the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. As of December 31, 2019, there was $24.1 million drawn and ~~conditions of~~outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an ~~accordion~~expansion 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, 2016, there was $12.5 million outstanding under~~ the ~~facility. As a result~~date of ~~Puget Energy's credit rating upgrade in 2014,~~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. For additional information, see Note 9, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report..

The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, ~~2016,~~2019, Puget Energy was in compliance with all applicable covenants.

~~(8)~~(9) Leases

PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets ~~under operating leases. Certain~~and lease liabilities include options to extend leases ~~contain purchase options, renewal options and escalation provisions.~~when it is reasonably certain that PSE will exercise that option.

During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease ~~expenses net~~right-of-use asset and Operating lease liabilities of ~~sublease receipts were:~~$14.7 million.

The components of lease cost were as follows:


Puget Energy and Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2019
Finance lease cost:
Amortization of right-of-use asset	$	562
Interest on lease liabilities	40
Total finance lease cost	$	602

Operating lease cost¹	$	20,639

_______________

^1.Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease.

102

(Dollars in Thousands)
At December 31,
Years Operating Lease Expense
2016 $ 31,786
2015 27,843
2014 30,737
Supplemental cash flow information related to leases was as follows:


Puget Energy and Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flow for operating leases	$	14,104
Investing cash flow for operating leases¹	6,535
Operating cash flow for finance leases	40
Financing cash flow for finance leases	562
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	$	5,976
Right-of-use assets obtained in exchange for new finance lease liabilities	745
Non-cash disclosure upon modification of existing lease
Modification of operating lease right-of-use assets	$	14,712

~~Payments received for~~_______________

¹ Includes $1.0 million allocated to PLNG at PE related to the ~~subleases~~Port of ~~properties were immaterial for each of~~Tacoma lease.

Supplemental balance sheet information related to leases was as follows:


Puget Sound Energy
(Dollars in Thousands)	At December 31,
Operating Leases	2019
Operating lease right-of-use asset	$	183,048

Operating leases liabilities current	15,862
Operating lease liabilities long-term	174,327
Total Operating lease liabilities:	$	190,189

Finance Leases
Common Plant	$	1,488

Other current liabilities	669
Other deferred credits	811
Total finance lease liabilities	$	1,480

Weighted Average Remaining Lease Term
Operating leases	19.24 Years
Finance leases	2.76 Years

Weighted Average Discount Rate
Operating leases	3.59		%
Finance leases	2.98		%

103

The following tables summarize the ~~years ended 2016, 2015 and 2014.~~

~~Future~~Company’s estimated future minimum lease payments ~~for non-cancelable~~as of December 31, 2019, and December 31, 2018, respectively:


Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2020	$	22,500	$	643
2021	22,527		508
2022	21,856		279
2023	21,415		98
2024	20,690		—
Thereafter	160,410		—
Total lease payments	$	269,398	$	1,528
Less imputed interest	(79,209)		(48)
Total net present value	$	190,189	$	1,480


Maturities of lease liabilities	Future Minimum Lease Payments
(Dollars in Thousands)
At December 31,	Operating Leases		Finance Leases
2019	$	20,635	$	495
2020	20,704		446
2021	20,630		311
2022	20,202		82
2023	19,223		—
Thereafter	132,889		—
Total lease payments	$	234,283	$	1,334

PSE adopted ASU 2016-02 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. For further details see Note 2, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts ~~are:~~are presented in the following table.


(Dollars in Thousands)	Operating Lease Expense
Year Ended December 31,
2018	$	34,093
2017	35,198

104

(Dollars in Thousands)
At December 31, Future Minimum Lease Payments
Years Operating Capital
2017 $ 22,212
$ 296
2018 19,834
296
2019 18,078
74
2020 16,507
—
2021 8,137
—
Thereafter 102,393
—
Total minimum lease payments $ 187,161
$ 666

~~(9)~~(10) Accounting for Derivative Instruments and Hedging Activities

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

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

The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of December 31, 2016, Puget Energy had two interest rate swap contracts outstanding which matured January 2017. Currently, these swap instruments do not hedge any variable interest rate debt. PSE did not have any outstanding interest rate swap instruments.

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


Puget Energy and Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)				Assets¹						Liabilities²
	2019	2018	2019		2018		2019		2018
Electric portfolio derivatives	*	*	$	19,933	$	33,287	$	17,504	$	27,284
Natural gas derivatives (MMBtus)³	316	337	11,375		15,732		8,617		30,472
Total derivative contracts			$	31,308	$	49,019	$	26,121	$	57,756
Current			23,626		46,507		13,428		46,661
Long-term			7,682		2,512		12,693		11,095
Total derivative contracts			$	31,308	$	49,019	$	26,121	$	57,756

Puget Energy and
Puget Sound Energy
At Year Ended December 31,
(Dollars in Thousands) Volumes (millions)
Assets¹
Liabilities²
2016 2015 2016 2015 2016 2015
Interest rate swap derivatives³
$450.0 $450.0 $ —
$ —
$ 141
$ 5,050
Electric portfolio derivatives * * 36,460
23,443
41,329
112,106
Natural gas derivatives (MMBtus)⁴
336.4
369.5
26,619
6,200
19,101
67,090
Total derivative contracts ** ** $ 63,079
$ 29,643
$ 60,571
$ 184,246
Current ** ** $ 54,341
$ 24,418
$ 44,310
$ 136,173
Long-term ** ** 8,738
5,225
16,261
48,073
Total derivative contracts ** ** $ 63,079
$ 29,643
$ 60,571
$ 184,246
__________

~~_______________~~^1.Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.


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


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


³	~~Interest rate swap contracts are only held at Puget Energy.~~


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


^*	Electric portfolio derivatives consist of electric generation fuel of 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015.


**	~~Not meaningful and/or applicable.~~

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

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

*Electric portfolio derivatives consist of electric generation fuel of 229.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 10.4 million megawatt hours (MWhs) at December 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note ~~10,~~11, "Fair Value ~~Measurements,"~~Measurements", to the consolidated financial statements included in Item 8 of this report.

105

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:


Puget Energy and Puget Sound Energy
December 31, 2019
(Dollars in Thousands)	Gross Amount Recognized in the Consolidated Balance Sheet¹		Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet
											Commodity Contracts²		Cash Collateral Received/Pledged	Net Amount
Assets:
Energy derivative contracts	$	31,308	$	—	$	31,308	$	(14,922)	$	—	$	16,386
Liabilities:
Energy derivative contracts	26,121		—		26,121		(14,922)		2,000		13,199


Puget Energy and Puget Sound Energy
December 31, 2018
(Dollars in Thousands)	Gross Amount Recognized¹		Gross Amounts Offset in the Consolidated Balance Sheet		Net of Amounts Presented in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet
											Commodity Contracts²		Cash Collateral Received/Pledged	Net Amount
Assets
Energy Derivative Contracts	$	49,019	$	—	$	49,019	$	(25,388)	$	—	$	23,631
Liabilities
Energy Derivative Contracts	57,756		—		57,756		(25,388)		—		32,368

__________

^1.All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off.

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

106

Puget Energy and
Puget Sound Energy

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

Puget Energy and
Puget Sound Energy

At December 31, 2015
(Dollars in Thousands)
Gross Amounts Recognized in the Statement of Financial Position¹
Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position
Commodity Contracts Cash Collateral Received/Posted Net Amount
Assets:
Energy derivative contracts $ 29,643
$ —
$ 29,643
$ (23,998 ) $ —
$ 5,645
Liabilities:
Energy derivative contracts 179,196
—
179,196
(23,998 ) —
155,198
Interest rate swaps²
5,050
—
5,050
—
—
5,050

~~_______________~~


¹	~~All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off.~~


²	~~Interest Rate Swap Contracts are only held at Puget Energy.~~

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

Puget Energy Year Ended December 31,
(Dollars in Thousands) Location 2016 2015 2014
Interest rate contracts:
Non-hedged interest rate swap (expense) income $ (1,062 ) $ (3,796 ) $ (3,915 )
Interest expense —
560
500
Gas for Power Derivatives:
Unrealized Unrealized gain (loss) on derivative instruments, net 62,318
(9,315 ) (42,334 )
Realized Electric generation fuel (39,656 ) (44,648 ) 6,511
Power Derivatives:
Unrealized
Unrealized gain (loss) on derivative instruments, net¹
21,477
22,548
(41,812 )
Realized Purchased electricity (21,998 ) (39,137 ) (4,212 )
Total gain (loss) recognized in income on derivatives $ 21,079
$ (73,788 ) $ (85,262 )


Puget Energy and Puget Sound Energy											Puget Energy and Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)											(Dollars in Thousands)	Location	2019		2018		2017
Interest rate contracts¹:											Interest rate contracts¹:
												Non-hedged interest rate swap (expense) income	$	—	$	—	$	28

Puget Sound Energy		Year Ended December 31,
(Dollars in Thousands)	Location	2016			2015			2014
Gas for Power Derivatives:											Gas for Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net	$	62,318		$	(9,315	)	$	(42,334	)	Unrealized	Unrealized gain (loss) on derivative instruments, net	16,970		23,186		(32,492)
Realized	Electric generation fuel	(39,656		)	(44,648		)	6,511			Realized	Electric generation fuel	10,828		26,222		(23,195)
Power Derivatives:											Power Derivatives:
Unrealized	Unrealized gain (loss) on derivative instruments, net¹	21,477			22,003			(43,302		)	Unrealized	Unrealized gain (loss) on derivative instruments, net	(20,544)		18,476		1,702
Realized	Purchased electricity	(21,998		)	(39,137		)	(4,212		)	Realized	Purchased electricity	48,686		12,240		(17,873)
Total gain (loss) recognized in income on derivatives		$	22,141		$	(71,097	)	$	(83,337	)	Total gain (loss) recognized in income on derivatives		$	55,940	$	80,124	$	(71,830)

_______________


¹	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015.

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

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

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

It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, ~~2016,~~2019, approximately ~~93.1%~~95.0% of the Company's energy portfolio exposure, excluding ~~NPNS~~normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and ~~6.9%~~5.0% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.

The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes

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

The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, ~~2016,~~2019, the Company was in a net ~~asset~~liability position with the majority of counterparties, ~~however,~~so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, ~~2016,~~2019, PSE had cash posted as collateral of $14.8 million related to contracts executed on the ICE platform. Also, as of December 31, 2019, PSE has ~~posted~~ a $1.0 million letter of credit posted as collateral as a condition of transacting on ~~a physical energy exchange and clearinghouse in Canada.~~the ICE NGX exchange. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, ~~2016,~~2019, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

107

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


Puget Energy and Puget Sound Energy	At December 31,												Puget Energy and Puget Sound Energy	December 31,
(Dollars in Thousands)	2016						2015						(Dollars in Thousands)	2019										2018
Contingent Feature	Fair Value¹ Liability		Posted Collateral		Contingent Collateral		Fair Value¹ Liability		Posted Collateral		Contingent Collateral		Contingent Feature	Fair Value¹ Liability		Posted Collateral		Contingent Collateral		Fair Value¹ Liability		Posted Collateral		Contingent Collateral
Credit rating²	$	4,894	$	—	$	4,894	$	24,187	$	—	$	24,187	Credit rating²	$	6,110	$	—	$	6,110	$	574	$	—	$	574
Requested credit for adequate assurance	7,427		—		—		67,003		—		—		Requested credit for adequate assurance	5,253		—		—		18,495		—		—
Forward value of contract³	507		—		—		—		—		—		Forward value of contract³	—		14,827		N/A		—		—		—
Total	$	12,828	$	—	$	4,894	$	91,190	$	—	$	24,187	Total	$	11,363	$	14,827	$	6,110	$	19,069	$	—	$	574

_______________


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


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


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

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

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

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

~~(10)~~

(11) Fair Value Measurements

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

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

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

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

Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price ~~curves;~~curves, contract terms and ~~prices;~~prices, credit-risk ~~adjustments;~~adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs ~~because~~as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.

108

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

Assets and Liabilities with Estimated Fair Value

The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of ~~$49.1~~$51.5 million and ~~$52.8~~$49.5 million at December 31, ~~2016~~2019, and ~~2015,~~2018, respectively, are included in ~~other~~"Other property and ~~investments~~investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions.

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

Puget Energy At December 31, 2016 At December 31, 2015
(Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value
Liabilities:
Junior subordinated notes 2 $ 250,000
$ 210,261
$ 250,000
$ 211,173
Long-term debt (fixed-rate), net of discount¹
2 5,091,593
6,337,287
5,077,518
6,308,831
Long-term debt (variable-rate) 2 12,480
12,480
—
—
Total $ 5,354,073
$ 6,560,028
$ 5,327,518
$ 6,520,004

Puget Sound Energy At December 31, 2016 At December 31, 2015
(Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value
Liabilities:
Junior subordinated notes 2 $ 250,000
$ 210,261
$ 250,000
$ 211,173
Long-term debt (fixed-rate), net of discount²
2 3,497,298
4,360,783
3,494,362
4,329,444
Total $ 3,747,298
$ 4,571,044
$ 3,744,362
$ 4,540,617

~~_______________~~


¹	~~The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015, respectively, which are not included in fair value.~~


²	~~The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015, respectively, which are not included in fair value.~~


Puget Energy		December 31, 2019						December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial liabilities:

Long-term debt (fixed-rate), net of discount¹	2	$	5,512,225	$	7,004,316	$	5,510,591	$	6,443,742
Long-term debt (variable-rate), net of discount	2	408,100		408,100		161,900		161,900
Total		$	5,920,325	$	7,412,416	$	5,672,491	$	6,605,642

Puget Sound Energy		December 31, 2019						December 31, 2018
(Dollars in Thousands)	Level	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial liabilities:

Long-term debt (fixed-rate), net of discount²	2	$	4,336,142	$	5,571,818	$	3,894,860	$	4,574,611
Total		$	4,336,142	$	5,571,818	$	3,894,860	$	4,574,611

_______________

^1.The carrying value includes debt issuances costs of $24.1 million and $26.1 million for December 31, 2019, and 2018, respectively, which are not included in fair value.

^2.The carrying value includes debt issuances costs of $24.4 million and $24.6 million for December 31, 2019, and 2018, respectively, which are not included in fair value.

109

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:


Puget Energy	Fair Value
	At December 31, 2016						At December 31, 2015
Puget Energy and Puget Sound Energy													Puget Energy and Puget Sound Energy	Fair Value											Fair Value
																December 31, 2019											December 31, 2018
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total		(Dollars in Thousands)	Level 2			Level 3		Total		Level 2		Level 3		Total
Assets:													Assets:
Electric Derivative Instruments													Electric Derivative Instruments	$	19,282		$	651	$	19,933	$	28,765	$	4,522	$	33,287
Gas Derivative Instruments													Gas Derivative Instruments	9,852			1,523		11,375		12,247		3,485		15,732
Total derivative assets													Total derivative assets	$	29,134		$	2,174	$	31,308	$	41,012	$	8,007	$	49,019
Liabilities:													Liabilities:
Interest rate derivative instruments	$	141	$	—	$	141	$	5,050	$	—	$	5,050
Electric Derivative Instruments													Electric Derivative Instruments	$	13,474		$	4,030	$	17,504	$	24,124	$	3,160	$	27,284
Gas Derivative Instruments													Gas Derivative Instruments	8,376			241		8,617		28,660		1,812		30,472
Total derivative liabilities	$	141	$	—	$	141	$	5,050	$	—	$	5,050	Total derivative liabilities	$	21,850		$	4,271	$	26,121	$	52,784	$	4,972	$	57,756


Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net Asset(Liability)	2019										2018								2017
(Dollars in Thousands)	Electric		Natural Gas		Total		Electric		Natural Gas		Total		Electric		Natural Gas		Total
Balance at beginning of period	$	1,362	$	1,673	$	3,035	$	1,098	$	1,923	$	3,021	$	972	$	625	$	1,597
Changes during period
Realized and unrealized energy derivatives:
Included in earnings¹	3,558		—		3,558		34,604		—		34,604		2,781		—		2,781
Included in regulatory assets / liabilities	—		3,151		3,151		—		6,075		6,075		—		6,346		6,346
Settlements²	(11,265)		(4,708)		(15,973)		(33,067)		(7,197)		(40,264)		(6,549)		(6,372)		(12,921)
Transferred into Level 3	4,390		(398)		3,992		(1,987)		—		(1,987)		523		(553)		(30)
Transferred out Level 3	(1,424)		1,564		140		714		872		$	1,586	3,371		1,877		$	5,248
Balance at end of period	$	(3,379)	$	1,282	$	(2,097)	$	1,362	$	1,673	$	3,035	$	1,098	$	1,923	$	3,021

Puget Energy and
Puget Sound Energy Fair Value Fair Value
At December 31, 2016 At December 31, 2015
(Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total
Assets:
Electric derivative instruments $ 30,666
$ 5,794
$ 36,460
$ 10,709
$ 12,734
$ 23,443
Natural gas derivative instruments 23,316
3,303
26,619
4,538
1,662
6,200
Total derivative assets $ 53,982
$ 9,097
$ 63,079
$ 15,247
$ 14,396
$ 29,643
Liabilities:

Electric derivative instruments $ 36,507
$ 4,822
$ 41,329
$ 92,027
$ 20,079
$ 112,106
Natural gas derivative instruments 16,423
2,678
19,101
63,045
4,045
67,090
Total derivative liabilities $ 52,930
$ 7,500
$ 60,430
$ 155,072
$ 24,124
$ 179,196

^{__________________}

^1.Income Statement classification: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(3.2) million, $1.1 million and $1.5 million for the years ended December 31, 2019, 2018, and 2017, respectively.

Puget Energy and
Puget Sound Energy
Year Ended December 31,
Level 3 Roll-Forward Net (Liability) 2016 2015 2014
(Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total
Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 )
Changes during period

Realized and unrealized energy derivatives:

Included in earnings¹
4,007
—
4,007
(6,432 ) —
(6,432 ) (5,537 ) —
(5,537 )
Included in regulatory assets / liabilities —
4,312
4,312
—
3,695
3,695
—
1,630
1,630
Settlements²
(1,129 ) (2,679 ) (3,808 ) 902
(3,885 ) (2,983 ) 1,036
(1,534 ) (498 )
Transferred into Level 3 (3,021 ) —
(3,021 ) (787 ) —
(787 ) 5,155
(585 ) 4,570
Transferred out of Level 3 8,460
1,375
9,835
11,034
(153 ) 10,881
2,705
(1,190 ) 1,515
Balance at end of period $ 972
$ 625
$ 1,597
$ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 )
^2.The Company had no purchases, sales or issuances during the reported periods.

~~_______________~~


¹	Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $2.0 million, ~~$(7.4) million~~ ~~and~~ ~~$(9.6) million~~ ~~for the years ended December 31, 2016, 2015 and 2014, respectively.~~


²	~~The Company had no purchases, sales or issuances during the reported periods.~~

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

In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month

110

and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, ~~2016~~2019, 2018, and ~~2015~~.2017. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.

The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts.

Below are the forward price ranges for the Company's commodity contracts, as of December 31, ~~2016:~~2019:

Puget Energy and
Puget Sound Energy

Fair Value

Range

Puget Energy and
Puget Sound Energy

Fair Value

Range

(Dollars in Thousands)

Assets¹

Liabilities¹

Valuation Technique

Unobservable Input

Low

High

Weighted Average

(Dollars in Thousands)

Assets¹

Liabilities¹

Valuation Technique

Unobservable Input

Low

High

Weighted

Electric

$5,794

$4,822

Discounted cash flow

Power Prices

$11.86 per MWh

$33.52 per MWh

$27.61 per MWh

Natural gas

$3,303

$2,678

Discounted cash flow

Natural Gas Prices

$2.00 per MMBtu

$3.24 per MMBtu

$2.42 per MMBtu

Electricity

651

4,030

Discounted cash flow

Power Prices (per MWh)

9.00

43.85

33.99

Natural Gas

1,523

241

Discounted cash flow

Natural Gas Prices (per MMBtu)

1.25

3.18

2.47

_______________


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

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

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, ~~2016,~~2019, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by ~~$0.2~~$2.5 million.

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

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

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

Puget Energy evaluated the triggering event criteria in ASC 360 during 2019 and determined there was no indication of impairment of its power purchase contracts. During ~~2016~~2018, decreases in forward power prices and ~~2015,~~decreases in forecasted revenue and cost estimates indicated the carrying value of Puget Energy’s power purchase contracts may not have been recoverable. Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In ~~2016 and 2015, due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices,~~2018, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:


Puget Energy								Puget Energy
(Dollars in Thousands)								(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down		Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2016	Priest Rapids	$	18,969	$	6,191	$	12,778
March 31, 2016	Wells Hydro	25,193		19,855		5,338
December 31, 2015	Wells Hydro	32,988		27,628		5,360
March 31, 2018								March 31, 2018	Wells Hydro	$	4,302	$	2,395	$	1,907
Total 2018 Impairments								Total 2018 Impairments						$	1,907

The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates ~~which are~~ classified as Level

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3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.

Below are significant unobservable inputs used in estimating the impaired ~~long term~~long-term power purchase contracts' fair value in ~~2016~~2019 and ~~2015:~~2018:


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



~~Puget Energy~~
~~Valuation Date~~	~~Unobservable Input~~	~~Low~~	~~High~~	~~Average~~
~~September 30, 2016~~
	~~Power prices~~	~~$24.24 per MWh~~	~~$58.96 per MWh~~	~~$39.31 per MWh~~
	~~Power contract costs (in thousands)~~	~~$618 per year~~	~~$4,633 per year~~	~~$2,472 per year~~
~~March 31, 2016~~
	~~Power prices~~	~~$9.46 per MWh~~	~~$25.96 per MWh~~	~~$21.38 per MWh~~
	~~Power contract costs (in thousands)~~	~~$4,100 per qtr.~~	~~$4,659 per qtr.~~	~~$4,452 per qtr.~~
~~December 31, 2015~~
	~~Power prices~~	~~$15.16 per MWh~~	~~$27.25 per MWh~~	~~$23.23 per MWh~~
	~~Power contract costs (in thousands)~~	~~$4,100 per qtr.~~	~~$4,659 per qtr.~~	~~$4,417 per qtr.~~

~~(11)~~(12) Employee Investment Plans

The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were ~~$17.2~~$21.7 million, ~~$16.1~~$20.7 million and ~~$14.9~~$19.2 million for the years ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents.

Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions:

1.For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6%6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1%1.0% of base pay.

2.For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match ~~55%~~55.0% of an employee’s contribution up to 6%6.0% of plan compensation each paycheck.

Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below:

1.401(k) Company Matching: ~~New~~For non-represented, UA-represented and IBEW-represented employees PSE will ~~receive company match each paycheck based on a new schedule-100%~~match: 100% match on the first 3%3.0% of pay contributed and ~~50%~~50.0% match on the next 3%3.0% of pay ~~contributed. An~~contributed, such that an employee who contributes 6%6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

2.Company Contribution: ~~New~~For UA-represented employees will receive an annual company contribution of 4%4.0% of eligible pay placed in the Cash Balance retirement plan. ~~New non-represented~~Non-represented and IBEW-represented employees will receive an annual company contribution of 4%4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. ~~New non-represented~~Non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4%4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The ~~Company’s 4%~~Company's 4.0% contribution will vest after three years of service.

~~(12)~~(13) Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering ~~the largest portion~~a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014, all ~~non-represented and UA-represented~~UA represented employees ~~along with IBEW-represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution~~will receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula ~~portion~~plan of the ~~pension plan,~~defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual employer contributions of 4.0% of eligible pay ~~credits~~each year in the cash balance formula of ~~4% each year. They will~~the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, ~~like other participants in the cash balance pension formula of the pension plan,~~ which are at least 1%1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, ~~he or she~~they will have annuity and lump sum options for distribution. ~~Those who select the lump sum option will receive their current cash balance amount.~~ PSE also ~~maintains~~has a non-qualified Supplemental Executive Retirement Plan (SERP) for ~~its~~certain key senior management ~~employees.~~employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019,

112

such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an account with the Deferred Compensation Plan.

In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries.

Puget ~~Energy records purchase accounting adjustments associated with the re-measurement~~Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans.

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

The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, ~~2016~~2019, and ~~2015:~~2018:


Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Change in benefit obligation:
Benefit obligation at beginning of period	$	677,643	$	700,481	$	55,708	$	55,754	$	10,636	$	11,454
Amendments	—		—		—		1,446		9,049		—
Service cost	22,656		22,757		1,023		847		61		69
Interest cost	28,913		27,303		2,314		2,120		410		444
Curtailment Loss / (Gain)	—		—		—		—		(7,486)		—
Actuarial loss (gain)	84,272		(29,067)		6,756		1,122		(287)		(379)
Benefits paid	(36,740)		(42,662)		(2,801)		(5,581)		(982)		(1,037)
Medicare part D subsidy received	—		—		—		—		226		85
Administrative expense	(2,439)		(1,169)		—		—		—		—
Benefit obligation at end of period	$	774,305	$	677,643	$	63,000	$	55,708	$	11,627	$	10,636

113

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Change in benefit obligation:
Benefit obligation at beginning of period $ 643,088
$ 690,194
$ 51,279
$ 55,855
$ 13,946
$ 15,688
Service cost 18,913
21,287
1,085
1,108
93
112
Interest cost 28,689
28,088
2,325
2,281
533
621
Actuarial loss (gain) 1,545
(55,665 ) 106
(4,430 ) (2,262 ) (1,416 )
Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 )
Medicare part D subsidy received —
—
—
—
148
295
Administrative expense (898 ) (853 ) —
—
—
—
Benefit obligation at end of period $ 652,607
$ 643,088
$ 51,734
$ 51,279
$ 11,194
$ 13,946


Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Change in plan assets:
Fair value of plan assets at beginning of period	$	640,242	$	704,360	$	—	$	—	$	5,960	$	7,138
Actual return on plan assets	133,939		(38,379)		—		—		1,006		(395)
Employer contribution	18,000		18,000		2,801		5,581		305		254
Benefits paid	(36,740)		(42,662)		(2,801)		(5,581)		(982)		(1,037)
Administrative expense	(2,399)		(1,077)		—		—		—		—
Fair value of plan assets at end of period	$	753,042	$	640,242	$	—	$	—	$	6,289	$	5,960
Funded status at end of period	$	(21,263)	$	(37,401)	$	(63,000)	$	(55,708)	$	(5,338)	$	(4,676)

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Change in plan assets:
Fair value of plan assets at beginning of period $ 598,865
$ 626,173
$ —
$ —
$ 7,203
$ 8,360
Actual return on plan assets 37,022
(4,489 ) —
—
926
(378 )
Employer contribution 24,000
18,000
3,061
3,535
335
575
Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 )
Administrative expense (897 ) (856 ) —
—
—
—
Fair value of plan assets at end of period $ 620,260
$ 598,865
$ —
$ —
$ 7,200
$ 7,203
Funded status at end of period $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 )


Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Amounts recognized in Consolidated Balance Sheet consist of:
Noncurrent assets	$	—	$	—	$	—	$	—	$	—	$	—
Current liabilities	—		—		(22,604)		(6,249)		(308)		(332)
Noncurrent liabilities	(21,263)		(37,401)		(40,396)		(49,459)		(5,030)		(4,344)
Net assets (liabilities)	$	(21,263)	$	(37,401)	$	(63,000)	$	(55,708)	$	(5,338)	$	(4,676)


Puget Energy and Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation	$	774,305	$	677,643	$	63,000	$	55,708	$	11,627	$	10,636
Accumulated benefit obligation	762,838		668,469		59,988		51,031		11,604		10,557
Fair value of plan assets	753,042		640,242		—		—		6,289		5,960

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Amounts recognized in Statement of Financial Position consist of:
Noncurrent assets $ —
$ —
$ —
$ —
$ —
$ —
Current liabilities —
—
(1,911 ) (2,545 ) (325 ) (353 )
Noncurrent liabilities (32,347 ) (44,223 ) (49,823 ) (48,734 ) (3,669 ) (6,390 )
Net assets (liabilities) $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 )

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets:
Projected benefit obligation $ 652,607
$ 643,088
$ 51,734
$ 51,279
$ 11,194
$ 13,946
Accumulated benefit obligation 641,855
635,599
47,639
46,978
11,092
13,828
Fair value of plan assets 620,260
598,865
—
—
7,200
7,203

The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, ~~2016~~2019, and ~~2015~~:2018:


Puget Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	94,319	$	94,929	$	15,003	$	9,612	$	(197)	$	(2,564)
Prior service cost (credit)	(3,884)		(5,863)		1,276		1,607		—		—
Total	$	90,435	$	89,066	$	16,279	$	11,219	$	(197)	$	(2,564)

114


Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
Puget Sound Energy																	Puget Sound Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2016			2015			2016		2015		2016			2015			(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Amounts recognized in Accumulated Other Comprehensive Income consist of:																	Amounts recognized in Accumulated Other Comprehensive Income consist of:
Net loss (gain)	$	56,588		$	45,447		$	9,043	$	9,848	$	(4,190	)	$	(1,834	)	Net loss (gain)	$	217,502	$	229,819	$	16,473	$	11,450	$	(364)	$	(3,857)
Prior service cost (credit)	(9,822		)	(11,802		)	246		288		—			—			Prior service cost (credit)	(3,086)		(4,659)		1,276		1,609		—		—
Total	$	46,766		$	33,645		$	9,289	$	10,136	$	(4,190	)	$	(1,834	)	Total	$	214,416	$	225,160	$	17,749	$	13,059	$	(364)	$	(3,857)

Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Amounts recognized in Accumulated Other Comprehensive Income consist of:

Net loss (gain) $ 217,143
$ 221,064
$ 11,978
$ 13,202
$ (5,994 ) $ 3,834
Prior service cost (credit) (7,806 ) (9,379 ) 251
295
—
—
Total $ 209,337
$ 211,685
$ 12,229
$ 13,497
$ (5,994 ) $ 3,834

The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, ~~2016~~, ~~2015~~2019, 2018, and ~~2014~~:2017.


Puget Energy	Qualified Pension Benefits										SERP Pension Benefits								Other Benefits
(Dollars in Thousands)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Components of net periodic benefit cost:
Service cost	$	22,656	$	22,757	$	20,081	$	1,023	$	847	$	913	$	61	$	69	$	72
Interest cost	28,913		27,303		28,373		2,314		2,120		2,285		410		444		500
Expected return on plan assets	(50,249)		(50,202)		(47,784)		—		—		—		(393)		(472)		(461)
Amortization of prior service cost (credit)	(1,980)		(1,980)		(1,980)		331		1,580		42		—		—		—
Amortization of net loss (gain)	1,151		2,187		—		1,365		42		1,077		(374)		(335)		(402)
Net periodic benefit cost	$	491	$	65	$	(1,310)	$	5,033	$	4,589	$	4,317	$	(296)	$	(294)	$	(291)


Puget Sound Energy	Qualified Pension Benefits										SERP Pension Benefits								Other Benefits
(Dollars in Thousands)	2019		2018		2017		2019		2018		2017		2019		2018		2017
Components of net periodic benefit cost:
Service cost	$	22,656	$	22,757	$	20,081	$	1,023	$	847	$	913	$	61	$	69	$	72
Interest cost	28,913		27,303		28,373		2,314		2,120		2,285		410		444		500
Expected return on plan assets	(50,267)		(50,240)		(47,862)		—		—		—		(393)		(472)		(461)
Amortization of prior service cost (credit)	(1,573)		(1,573)		(1,573)		333		44		44		—		—		—
Amortization of net loss (gain)	12,877		14,917		13,048		1,733		2,069		1,565		(562)		(556)		(641)
Net periodic benefit cost	$	12,606	$	13,164	$	12,067	$	5,403	$	5,080	$	4,807	$	(484)	$	(515)	$	(530)

115

Puget Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014
Components of net periodic benefit cost:
Service cost $ 18,913
$ 21,287
$ 17,437
$ 1,085
$ 1,108
$ 1,042
$ 93
$ 112
$ 112
Interest cost 28,689
28,088
28,039
2,325
2,281
2,310
533
621
684
Expected return on plan assets (46,619 ) (45,038 ) (42,464 ) —
—
—
(446 ) (531 ) (535 )
Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42
42
42
—
—
—
Amortization of net loss (gain) —
3,887
—
911
1,641
913
(386 ) (130 ) (393 )
Net periodic benefit cost $ (997 ) $ 6,244
$ 1,032
$ 4,363
$ 5,072
$ 4,307
$ (206 ) $ 72
$ (132 )

Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014
Components of net periodic benefit cost:
Service cost $ 18,913
$ 21,287
$ 17,437
$ 1,085
$ 1,108
$ 1,042
$ 93
$ 112
$ 112
Interest cost 28,689
28,088
28,039
2,325
2,281
2,310
533
621
684
Expected return on plan assets (46,814 ) (45,462 ) (43,252 ) —
—
—
(446 ) (531 ) (535 )
Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44
44
44
—
3
3
Amortization of net loss(gain) 15,257
20,555
13,195
1,330
2,120
1,461
(632 ) (406 ) (702 )
Net periodic benefit cost $ 14,472
$ 22,895
$ 13,846
$ 4,784
$ 5,553
$ 4,857
$ (452 ) $ (201 ) $ (438 )

The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, ~~2016~~2019, and ~~2015~~:2018:


Puget Energy	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	541	$	59,422	$	6,756	$	1,122	$	(900)	$	488
Amortization of net (loss) gain	(1,151)		(2,187)		(1,365)		(1,580)		374		335
Settlements, mergers, sales, and closures	—		—		—		(619)		2,892		—
Prior service cost (credit)	—		—		—		1,446		—		—
Amortization of prior service (cost) credit	1,980		1,980		(331)		(42)		—		—
Total change in other comprehensive income for year	$	1,370	$	59,215	$	5,060	$	327	$	2,366	$	823

Puget Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain) $ 11,141
$ (6,136 ) $ 106
$ (4,430 ) $ (2,742 ) $ (508 )
Amortization of net loss (gain) —
(3,887 ) (910 ) (1,641 ) 385
131
Amortization of prior service credit 1,980
1,980
(42 ) (42 ) —
—
Total change in other comprehensive income for year $ 13,121
$ (8,043 ) $ (846 ) $ (6,113 ) $ (2,357 ) $ (377 )


Puget Sound Energy	Qualified Pension Benefit						SERP Pension Benefits						Other Benefits
(Dollars in Thousands)	2019		2018		2019		2018		2019		2018
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	$	559	$	59,460	$	6,756	$	1,122	$	(900)	$	488
Amortization of net (loss) gain	(12,877)		(14,917)		(1,733)		(2,069)		562		556
Settlements, mergers, sales, and closures	—		—		—		(737)		3,832		—
Prior service cost (credit)	—		—		—		1,446		—		—
Amortization of prior service (cost) credit	1,573		1,573		(333)		(44)		—		—
Total change in other comprehensive income for year	$	(10,745)	$	46,116	$	4,690	$	(282)	$	3,494	$	1,044

Puget Sound Energy
Qualified
Pension Benefit
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands) 2016 2015 2016 2015 2016 2015
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain) $ 11,336
$ (5,711 ) $ 106
$ (4,430 ) $ (2,742 ) $ (508 )
Amortization of net (loss) gain (15,257 ) (20,556 ) (1,330 ) (2,120 ) 631
407
Amortization of prior service cost (credit) 1,573
1,573
(44 ) (44 ) —
(3 )
Total change in other comprehensive income for year $ (2,348 ) $ (24,694 ) $ (1,268 ) $ (6,594 ) $ (2,111 ) $ (104 )

The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from ~~accumulated OCI~~AOCI into net periodic benefit cost in ~~2017~~2020 by PSE ~~are $(13.7)~~include a $18.6 million net loss and ~~$(1.6)~~a $1.6 million credit, respectively. The estimated net (loss) gain ~~for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is $(1.6) million. The estimated~~and prior service cost (credit) for the SERP that will be amortized from ~~accumulated OCI~~AOCI into net periodic benefit cost in ~~2017~~2020 is ~~immaterial.~~a $2.6 million net loss and a $0.3 million net loss, respectively. The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from ~~accumulated OCI~~AOCI into net periodic benefit cost in ~~2017~~2020 is ~~immaterial.~~a net loss of $0.2 million. For Puget Energy, the overall amounts expected to be amortized from ~~accumulated OCI~~AOCI into net period benefit cost in ~~2017 were immaterial.~~2020 is a net loss of $8.4 million.

The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, ~~2017~~2020, are expected to be at least $18.0 million, ~~$1.9~~$22.6 million and ~~$0.3~~$0.1 million, respectively.

116

Assumptions

In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company:


	Qualified Pension Benefits						SERP Pension Benefits						Other Benefits							Qualified Pension Benefits										SERP Pension Benefits								Other Benefits
Benefit Obligation Assumptions	2016		2015		2014		2016		2015		2014		2016		2015		2014		Benefit Obligation Assumptions	2019		2018		2017		2019		2018		2017		2019		2018		2017
Discount rate	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%	4.50	%	4.65	%	4.25	%	Discount rate	3.35	%	4.40	%	4.00	%	3.35	%	4.40	%	4.00	%	3.35	%	4.40	%	4.00	%
Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Medical trend rate	—		—		—		—		—		—		8.80		7.20		5.70
Medical trend rate¹																			Medical trend rate¹	—		—		—		—		—		—		N/A		7.60		6.80
Benefit Cost Assumptions																			Benefit Cost Assumptions
Discount rate	4.65	%	4.25	%	5.10	%	4.65	%	4.25	%	5.10	%	4.65	%	4.25	%	5.10	%	Discount rate	4.40		4.40		4.50		4.40		4.40		4.50		4.40		4.40		4.50
Return on plan assets	7.75		7.75		7.75		—		—		—		6.75		7.00		7.00		Return on plan assets	7.50		7.50		7.45		—		—		—		7.00		7.00		6.75
Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		Rate of compensation increase	4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50		4.50
Medical trend rate	—		—		—		—		—		—		5.30		7.20		6.70
Medical trend rate¹																			Medical trend rate¹	—		—		—		—		—		—		N/A		7.60		9.50

^{________________________}

~~The assumed~~^1.As of December 31,2019, PSE terminated the previous group retiree medical plan and created an HRA. As a result, medical inflation ~~rate used to determine~~is no longer applicable in accounting for the related benefit ~~obligations is 8.80% in 2017 grading down to 4.30% in 2018. A 1.0% change in the assumed medical inflation rate would have the following effects:~~obligation.

2016 2015
(Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease
Effect on post-retirement benefit obligation $ 38
$ (35 ) $ 52
$ (42 )
Effect on service and interest cost components 2
(2 ) 2
(2 )

The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is ~~as follows. PSE market-related value of assets is~~ based on a five-year smoothing of asset gains (losses) measured from the

expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year.

Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, and mortality ~~and health care costs~~ trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger.

The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities.

Plan Benefits

The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows:


(Dollars in Thousands)	2020		2021		2022		2023		2024		2025-2029
Qualified Pension total benefits	$	45,000	$	45,200	$	46,200	$	47,900	$	48,800	$	253,400
SERP Pension total benefits	22,604		1,940		5,792		3,663		6,290		21,283
Other Benefits total with Medicare Part D subsidy	843		826		972		937		901		4,053
Other Benefits total without Medicare Part D subsidy	1,055		1,007		972		937		901		4,053

117

(Dollars in Thousands) 2017
2018
2019
2020
2021
2022-2026
Qualified Pension total benefits $ 41,400
$ 42,500
$ 43,600
$ 44,600
$ 45,200
$ 240,800
SERP Pension total benefits 1,911
5,278
5,666
4,454
1,724
34,043
Other Benefits total with Medicare Part D subsidy 928
893
863
829
787
3,873
Other Benefits total without Medicare Part D subsidy 1,256
1,239
1,216
1,191
1,158
5,294

Plan Assets

Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements.

The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented.

The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant.

To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows:


	Allocation
Asset Class	Minimum		Target		Maximum
Domestic large cap equity	25	%	31	%	40	%
Domestic small cap equity	—		9		15
Non-U.S. equity	10		25		30
Fixed income	15		25		30
Real estate	—		—		10
Absolute return	5		10		15
Cash	—		—		5

Plan Fair Value Measurements

ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets.

ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share.

118

The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, ~~2016~~2019, and ~~2015:~~2018:


	Recurring Fair Value Measures										Recurring Fair Value Measures
	December 31, 2019										December 31, 2018
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual Funds	$	91,658	$	—	$	91,658	$	103,661	$	—	$	103,661
Common Stock	224,146		—		224,146		177,949		—		177,949
Government Securities	34,916		—		34,916		—		—		—
Corporate Bonds	—		—		—		—		—		—
Cash and cash equivalents	—		150		150		—		702		702
Subtotal	$	350,720	$	150	$	350,870	$	281,610	$	702	$	282,312
Investments measured at NAV¹					401,668						356,586
Net (payable) receivable					505						1,345
Total assets					$	753,043					$	640,243

Recurring Fair Value Measures Recurring Fair Value Measures
As of December 31, 2016 As of December 31, 2015
(Dollars in Thousands) Level 1
Level 2 Total Level 1 Level 2 Total
Assets:
Mutual Funds $ 181,212
$ —
$ 181,212
$ 169,165
$ —
$ 169,165
Common Stock 154,255
—
$ 154,255
146,321
—
$ 146,321
Government Securities 18,754
16,197
$ 34,951
8,835
14,268
$ 23,103
Corporate Bonds —
38,543
$ 38,543
—
44,157
$ 44,157
Subtotal 354,221
54,740
408,961
324,321
58,425
382,746
Investments measured at NAV¹
* * 222,819
* * 223,663
Net (payable) receivable * * (9,894 ) * * (7,544 )
Total assets * * $ 621,886
* * $ 598,865

~~_______________~~^{________________________}

^1.In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2019, and 2018.

In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of common/collective trust funds and two partnerships held as of December 31, 2016.

Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis.

Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.


*	~~Not Applicable.~~

The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value:


	Recurring Fair Value Measures										Recurring Fair Value Measures
	December 31, 2019										December 31, 2018
(Dollars in Thousands)	Level 1		Level 2		Total		Level 1		Level 2		Total
Assets:
Mutual fund¹	$	6,201	$	—	$	6,201	$	5,910	$	—	$	5,910
Investments measured at NAV²					88						50
Total assets					$	6,289					$	5,960

________________

^1.This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2019, and 2018.

^2.In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2019, and 2018.

119

~~_______________~~


¹	This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2016.


²	The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016. The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

~~(13)~~(14) Income Taxes

The details of income tax (benefit) expense are as follows:


Puget Energy	Year Ended December 31,									Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2016			2015			2014			(Dollars in Thousands)	2019		2018		2017
Charged to operating expenses:										Charged to operating expenses:
Current:										Current:
Federal	$	—		$	—		$	—		Federal	$	9,424	$	10,382	$	1,127
State	20			—			—			State	164		263		17
Deferred:										Deferred:
Federal	140,315			91,968			57,152			Federal	7,357		19,451		254,420
State	(131		)	(192		)	(167		)	State	128		(4)		(421)
Total income tax expense	$	140,204		$	91,776		$	56,985		Total income tax expense	$	17,073	$	30,092	$	255,143


Puget Sound Energy	Year Ended December 31,						Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2016		2015		2014		(Dollars in Thousands)	2019		2018		2017
Charged to operating expenses:							Charged to operating expenses:
Current:							Current:
Federal	$	—	$	—	$	—	Federal	$	18,093	$	19,283	$	1,127
State	20		—		—		State	570		438		17
Deferred:							Deferred:
Federal	175,327		125,900		89,342		Federal	20,485		30,979		210,842
State	—		—		—		State	—		—		—
Total income tax expense	$	175,347	$	125,900	$	89,342	Total income tax expense	$	39,148	$	50,700	$	211,986

The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2019 and 2018 and 35.0% in 2017 to the actual income tax expense in the Statements of Income:


Puget Energy	Year Ended December 31,
(Dollars in Thousands)	2019			2018			2017
Income taxes at the statutory rate	$	47,834		$	55,800		$	148,847
Increase (decrease):
Utility plant differences¹	$	(23,025)		$	(25,871)		$	—
AFUDC, net	(4,462)			(4,173)			(4,506)
Executive compensation	2,596			4,439			—
Treasury grant amortization	(7,870)			(4,861)			(9,537)
Tax reform	—			—			117,185
Other–net	2,000			4,758			3,154
Total income tax expense	$	17,073		$	30,092		$	255,143
Effective tax rate	7.5		%	11.3		%	60.0		%

120

Puget Energy Year Ended December 31,
(Dollars in Thousands) 2016 2015 2014
Income taxes at the statutory rate $158,586 $116,534 $80,087
Increase (decrease):
Production tax credit¹
(12,925) (19,470) (23,073)
Utility plant differences 3,966 5,671 7,090
Treasury grant amortization (9,788) (8,807) (8,808)
Other - net 365 (2,152) 1,689
Total income tax expense $140,204 $91,776 $56,985
Effective tax rate 30.9% 27.6% 24.9%


Puget Sound Energy	Year Ended December 31,			Puget Sound Energy	Year Ended December 31,
(Dollars in Thousands)	2016	2015	2014	(Dollars in Thousands)	2019			2018			2017
Income taxes at the statutory rate	$194,572	$150,531	$114,084	Income taxes at the statutory rate	$	69,735		$	77,251		$	185,430
Increase (decrease):				Increase (decrease):
Production tax credit¹	(12,925)	(19,470)	(23,073)
Utility plant differences	3,966	5,671	7,090
Utility plant differences¹				Utility plant differences¹	$	(23,025)		$	(25,871)		$	—
AFUDC, net				AFUDC, net	(4,462)			(4,173)			(4,506)
Executive Compensation				Executive Compensation	2,596			4,439			—
Treasury grant amortization	(9,788)	(8,807)	(8,808)	Treasury grant amortization	(7,870)			(4,861)			(9,537)
Other - net	(478)	(2,025)	49
Tax reform				Tax reform	—			—			36,328
Other–net				Other–net	2,174			3,915			4,271
Total income tax expense	$175,347	$125,900	$89,342	Total income tax expense	$	39,148		$	50,700		$	211,986
Effective tax rate	31.5%	29.3%	27.4%	Effective tax rate	11.8		%	13.8		%	40.0		%

_______________


¹	~~PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected.~~

^1.Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $29.8 million in 2019, and 2018, respectively.

The Company’s net deferred tax liability at December 31, ~~2016~~2019, and ~~2015~~2018, is composed of amounts related to the following types of temporary differences:


Puget Energy	At December 31,
(Dollars in Thousands)	2019		2018
Utility plant and equipment	$	1,943,730	$	1,998,721
Other deferred tax liabilities	133,440		113,051
Subtotal deferred tax liabilities	2,077,170		2,111,772
Net operating loss carryforward	(238,869)		(224,885)
Net regulatory liability for income taxes	(946,179)		(975,974)
Production tax credit carryforward	(67,402)		(121,616)
Subtotal deferred tax assets	(1,252,450)		(1,322,475)
Total net deferred tax liabilities	$	824,720	$	789,297

Puget Energy At December 31,
(Dollars in Thousands) 2016
2015
Utility plant and equipment $ 1,880,782
$ 1,788,078
Regulatory asset for income taxes 72,038
73,231
Fair value of debt instruments 67,444
70,260
Pensions and other compensation 77,230
77,230
Other, net deferred tax liabilities 119,050
84,397
Subtotal deferred tax liabilities 2,216,544
2,093,196
Net operating loss carryforward (352,827 ) (384,338 )
Production tax credit carryforward (190,999 ) (178,075 )
Regulatory liability on production tax credit (101,787 ) (94,828 )
Subtotal deferred tax assets (645,613 ) (657,241 )
Total net deferred tax liabilities
$ 1,570,931
$ 1,435,955


Puget Sound Energy	At December 31,
(Dollars in Thousands)	2019		2018
Utility plant and equipment	$	1,943,730	$	1,998,721
Other, net deferred tax liabilities	47,774		25,880
Subtotal deferred tax liabilities	1,991,504		2,024,601
Net regulatory liability for income taxes	(946,936)		(976,582)
Production tax credit carryforward	(67,405)		(121,616)
Subtotal deferred tax assets	(1,014,341)		(1,098,198)
Total net deferred tax liabilities	$	977,163	$	926,403

Puget Sound Energy At December 31,
(Dollars in Thousands) 2016
2015
Utility plant and equipment $ 1,880,782
$ 1,788,078
Regulatory asset for income taxes 71,517
72,694
Other, net deferred tax liabilities 113,938
80,351
Subtotal deferred tax liabilities 2,066,237
1,941,123
Net operating loss carryforward (41,061 ) (111,604 )
Production tax credit carryforward (190,999 ) (178,075 )
Regulatory liability on production tax credit (101,787 ) (94,828 )
Subtotal deferred tax assets (333,847 ) (384,507 )
Total net deferred tax liabilities
$ 1,732,390
$ 1,556,616

In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes". ASU 2015-17 requires reporting entities to classify deferred tax liabilities and assets as noncurrent in a classified balance sheet instead of separating such deferred taxes into current and noncurrent amounts.

The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. ~~The Company’s~~PSE’s PTC carryforwards expire from ~~2027~~2033 through 2036. ~~The Company’s~~Puget Energy’s net operating loss carryforwards expire from ~~2029~~2027 through ~~2036.~~2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for PTC or net operating loss carryforwards.

121

Federal Income Tax Law Changes

On December 22, 2017, President Trump signed into law legislation referred to as the TCJA. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% to 21.0% and the limitation of deductibility of executive compensation. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after December 31, 2017, and continues normalization requirements for accelerated depreciation benefits.

Under GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For ~~ratemaking purposes,~~PSE, the change in deferred taxes ~~are not provided for certain temporary differences. PSE has established~~is recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income.

Upon enactment of the TCJA, the Company re-measured its deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of 2017, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance was a liability of $1,012.3 million. Since PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be reversed over the remaining lives of the related assets using ARAM. The remainder of the net regulatory liability of $91.9 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017. For further details regarding PSE's ERF and Accounting Petition, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. In 2019 and 2018, the Company reversed excess deferred taxes for plant-related items using ARAM in the amount of $27.6 million and $29.8 million, respectively.

The impact of the TCJA to income tax expense as of December 31, 2017, was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the deferred tax for regulatory liability on PTC balances. The regulatory liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the new rate of 21.0%. The change in the liability owed to customers for PTCs increased revenue by $51.2 million, which increased tax expense by $17.9 million, to reverse the initial deferral. The changes in the deferred tax and the liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased its tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward.

The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA and on December 22, 2017, issued guidance in Staff Accounting Bulletin 118 (SAB 118). The guidance clarifies accounting for income taxes ~~recoverable through future rates related~~under ASC 740 if information is not yet available or complete and provides for up to ~~those temporary differences~~a one year period in which to complete the required analysis and accounting (the measurement period). The Company completed the required analysis and accounting for ~~which no deferred taxes have been provided, based on prior~~the effects of the TCJA's enactment and ~~expected future ratemaking treatment.~~did not identify any additional adjustments required.

Unrecognized Tax Benefits

The Company accounts for uncertain tax ~~position~~positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained.

As of December 31, ~~2016~~2019, and ~~2015~~,2018, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year.

The Company has open tax years from ~~2013~~2016 through ~~2016.~~2019. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

122

~~(14)~~(15) Litigation

Colstrip

PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. OnIn March 6, 2013,

the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. OnIn July ~~12,~~ 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court onin September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE ~~agreed, along with~~and Talen Energy ~~(the owner of the other 50% interest in Colstrip Units 1 and 2)~~Corporation (Talen), agreed to retire the ~~two~~2 oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. ~~PSE expects that the Washington Commission will allow full recovery in~~Depreciation rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. As a result, PSE reclassified $176.8 million from a plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the

~~expected shutdown date of July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations~~were updated in the ~~lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. While PSE has estimated the asset retirement obligation~~GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4.

Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of the year due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs ~~are unknown and will~~may vary from the estimates that are available at this time.

~~Greenwood~~

On ~~March 9, 2016, a natural gas explosion occurred~~December 10, 2019, PSE announced its intention to sell its interest in ~~the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed~~Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would retain its ~~investigation~~obligation to fund 25% of the ~~incident~~environmental remediation and ~~filed a complaint September 20, 2016, seeking from PSE $3.2 million in fines. As a result,~~decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission ~~will initiate~~and the Montana Public Service Commission. Additionally, PSE has agreed to enter into a ~~hearing before making~~power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a ~~final determination. As~~portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. PSE expects external parties to intervene on the contingent purchase agreement for Colstrip Unit 4. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, ~~2016,~~2019, and determined that these criteria were not met. As such, Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements included in Item 8 of this report.

Regional Haze Rule

In January 2017, the EPA published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, the EPA announced that it was reconsidering certain aspects of these revisions and PSE ~~has accrued $3.2 million~~is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the ~~fine.~~D.C. Circuit, pending resolution of the EPA’s reconsideration of the rule.

Clean Air Act 111(d)/EPA Affordable clean Energy Rule

In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule.

123

Washington Clean Air Rule

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

In September ~~27,~~ 2016, (United States District Court Eastern District of Washington) and Washington State court (Thurston County Superior Court) on September 30, 2016 challenging Washington Department of Ecology’s Clean Air Rule. Other parties in the suit includePSE, along with Avista Corporation, Cascade Natural Gas ~~Corp.~~Corporation and ~~Northwest~~NW Natural, ~~Gas. The~~filed a lawsuit ~~contends that this Rule will have the unintended consequence of increasing carbon emissions while penalizing customers for using natural gas.~~

~~Other Proceedings~~

~~The Company is also involved in litigation relating to claims arising out of its operations~~ in the ~~normal course~~U.S. District Court for the Eastern District of ~~business.~~Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The ~~Company~~Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. Meanwhile, the federal court litigation has ~~recorded reserves~~been held in abeyance pending resolution of ~~$0.7 million and $0.3 million relating to these claims as of December 31, 2016 and 2015, respectively.~~the state case.

~~(15)~~(16) Commitments and Contingencies

For the year ended December 31, ~~2016,~~2019, approximately ~~13.7%~~10.2% of the Company’s energy output was obtained at an average cost of approximately ~~$0.023~~$0.033 per Kilowatt Hour (kWh) through long-term contracts with ~~three~~3 of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed ~~through~~ substantially ~~level~~through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives.

The Company's expenses under these PUD contracts were as follows for the years ended December ~~31:~~31, :


(Dollars in Thousands)	2019		2018		2017
PUD contract costs	$	87,135	$	80,165	$	73,827

124

(Dollars in Thousands) 2016
2015
2014
PUD contract costs $ 77,667
$ 72,833
$ 69,661

As of December 31, ~~2016,~~2019, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table:


		Company's Current Share of													Company's Current Share of
(Dollars in Thousands)	Contract Expiration	Percent of Output		Megawatt Capacity	Estimated 2017 Costs		2017 Debt Service Costs		Interest included in 2017 Debt Service Costs		Debt Outstanding		(Dollars in Thousands)	Contract Expiration	Percent of Output		Megawatt Capacity	Estimated 2020 Costs		2020 Debt Service Costs		Interest included in 2020 Debt Service Costs		Debt Outstanding
Chelan County PUD:													Chelan County PUD:
Rock Island Project	2031	25.0	%	156	$	28,886	$	10,430	$	5,638	$	88,518	Rock Island Project	2031	25.0	%	156	$	34,180	$	11,499	$	5,681	$	96,956
Rocky Reach Project	2031	25.0		325	28,376		7,574		2,854		44,305		Rocky Reach Project	2031	25.0		325	31,190		4,940		2,129		33,317
Douglas County PUD:													Douglas County PUD:
Wells Project	2018	29.9		251	16,547		8,004		2,153		54,847
Wells Project¹													Wells Project¹	2028	27.1		228	43,004		—		—		—
Grant County PUD:													Grant County PUD:
Priest Rapids Development	2052	0.6		8	2,809		1,670		1,670		18,579		Priest Rapids Development	2052	0.6		6	1,831		1,085		586		12,793
Wanapum Development	2052	0.6		9	2,809		1,670		1,670		18,579		Wanapum Development	2052	0.6		7	1,831		1,085		586		12,793
Total				749	$	79,427	$	29,348	$	13,985	$	224,828	Total				722	$	112,036	$	18,609	$	8,982	$	155,859

_______________

^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.

The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts ~~with other utilities~~ and ~~contracts with non-utilities.~~electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions.


(Dollars in Thousands)	2017		2018		2019		2020		2021		Thereafter		Total		(Dollars in Thousands)	2020			2021		2022		2023		2024		Thereafter		Total
Columbia River projects	$	73,733	$	69,527	$	58,921	$	59,172	$	56,396	$	597,468	$	915,217	Columbia River projects	$	121,680		$	111,125	$	103,879	$	103,377	$	102,976	$	609,912	$	1,152,949
Other utilities	10,499		1,257		888		—		—		—		12,644
Non-utility contracts	198,681		203,428		208,328		212,042		218,431		935,826		1,976,736

Electric portfolio contracts															Electric portfolio contracts	263,940		��	300,795		302,838		307,888		315,593		969,383		2,460,437
Electric wholesale market transactions															Electric wholesale market transactions	188,822			24,901		3,190		—		—		—		216,913
Total	$	282,913	$	274,212	$	268,137	$	271,214	$	274,827	$	1,533,294	$	2,904,597	Total	$	574,442		$	436,821	$	409,907	$	411,265	$	418,569	$	1,579,295	$	3,830,299

Total purchased power contracts provided the Company with approximately ~~13.0~~12.5 million, ~~11.2~~14.1 million and ~~12.1~~14.5 million MWhs of firm energy at a cost of approximately ~~$402.5~~$550.6 million, ~~$373.8~~$508.2 million and ~~$401.4~~$456.4 million for the years ~~2016, 2015 and 2014, respectively.~~

PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815. Commitments under these contracts are $45.7 million, $10.5 million and $3.9 million in 2017,2019, 2018, and ~~2019,~~2017, respectively.

Natural Gas Supply Obligations

The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from ~~less than one~~1 year to 2825 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for ~~2016~~2019 for firm transportation, storage and peaking services for its natural gas customers of ~~$120.2~~$125.1 million. The Company incurred demand charges in ~~2016~~2019 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of ~~$43.2~~$51.2 million.

125

The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and ~~NEB (National~~CER (Canadian Energy ~~Board)~~Regulator) currently authorized rates, which are subject to change.


Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Natural gas portfolio contracts	$	273,263	$	196,806	$	178,208	$	148,165	$	82,509	$	—	$	878,951
Firm transportation service	176,741		173,133		172,190		161,508		116,842		828,136		1,628,550
Firm storage service	8,954		4,503		3,014		853		140		213		17,677
Total	$	458,958	$	374,442	$	353,412	$	310,526	$	199,491	$	828,349	$	2,525,178

Natural Gas Supply and Demand Charge Obligations
(Dollars in Thousands)
2017
2018
2019
2020
2021
Thereafter
Total
Natural gas supply $ 320,238
$ 211,256
$ 230,109
$ 177,390
$ 107,621
$ —
$ 1,046,614
Firm transportation service 156,290
154,155
149,277
140,672
128,049
467,266
1,195,709
Firm storage service 6,616
3,861
2,943
1,950
1,619
2,475
19,464
Total $ 483,144
$ 369,272
$ 382,329
$ 320,012
$ 237,289
$ 469,741
$ 2,261,787

Service Contracts

The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts.


Service Contract Obligations (Dollars in Thousands)	2020		2021		2022		2023		2024		Thereafter		Total
Energy production service contracts	$	28,474	$	29,219	$	29,923	$	30,645	$	31,400	$	141,817	$	291,478
Automated meter reading system	43,971		44,849		45,526		46,218		46,926		96,149		323,639
Total	$	72,445	$	74,068	$	75,449	$	76,863	$	78,326	$	237,966	$	615,117

Service Contract Obligations
(Dollars in Thousands)
2017
2018
2019
2020
2021
Thereafter
Total
Energy production service contracts $ 31,573
$ 31,970
$ 31,313
$ 50,656
$ 32,934
$ 204,687
$ 383,133
Automated meter reading system 18,175
18,693
18,718
20,191
20,939
116,811
213,527
Total $ 49,748
$ 50,663
$ 50,031
$ 70,847
$ 53,873
$ 321,498
$ 596,660

Other Commitments and Contingencies

For information regarding PSE's environmental remediation obligations, see Note 3,4, "Regulation and Rates," to the consolidated financial statements included in ~~item~~Item 8 of this report.

~~(16)~~(17) Related Party Transactions

~~Scott Armstrong serves on the Board of Directors of the~~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 and as a result, PSE paid Group Health a total of $23.3 million and $20.3 million for medical coverage foridentified no material related party transactions during the year ended December 31, ~~2016~~2019 and ~~2015, respectively.~~December 31, 2018.

~~Kimberly Harris, the President and Chief Executive Officer and a director of~~

(18) Segment Information

Puget Energy and PSE is married to Kyle Branum, who through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum is a partner at Summit Law Group, which provides legal services to PSE. In 2016 and 2015, Riddell Williams was paid $1.0 million and $1.8 million, respectively, for legal services provided to PSE and Mr. Branum was among the lawyers at Riddell Williams who provided such legal services. This work was performed under the supervision of PSE's General Counsel.

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, 2016 and 2015, Puget Energy and PSE paid a total of approximately $0.3 million and $1.0 million, respectively, in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.

~~(17) Segment Information~~

~~Puget Energy operates~~ ~~one~~operate 1 reportable ~~business~~ segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington. ~~In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year.~~

~~(18)~~

126

(19) Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively:


Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps						Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans
Changes in AOCI, net of tax													Changes in AOCI, net of tax
(Dollars in Thousands)										Total			(Dollars in Thousands)					Total
Balance at December 31, 2013	$	48,514		$	(705	)	$	(94	)	$	47,715
Balance at December 31, 2016													Balance at December 31, 2016	$	(33,712)	$	(33,712)
Other comprehensive income (loss) before reclassifications	(84,301		)	—			—			(84,301		)	Other comprehensive income (loss) before reclassifications	10,251		10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(923		)	372			94			(457		)	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(821)		(821)
Net current-period other comprehensive income (loss)	(85,224		)	372			94			(84,758		)	Net current-period other comprehensive income (loss)	9,430		9,430
Balance at December 31, 2014	$	(36,710	)	$	(333	)	$	—		$	(37,043	)
Balance at December 31, 2017													Balance at December 31, 2017	$	(24,282)	$	(24,282)
Other comprehensive income (loss) before reclassifications	7,196			—			—			7,196			Other comprehensive income (loss) before reclassifications	(48,870)		(48,870)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	2,248			333			—			2,581			Amounts reclassified from accumulated other comprehensive income (loss), net of tax	1,180		1,180
Reclassification of stranded taxes to retained earnings due to tax reform													Reclassification of stranded taxes to retained earnings due to tax reform	(5,230)		(5,230)
Net current-period other comprehensive income (loss)	9,444			333			—			9,777			Net current-period other comprehensive income (loss)	(52,920)		(52,920)
Balance at December 31, 2015	$	(27,266	)	$	—		$	—		$	(27,266	)
Balance at December 31, 2018													Balance at December 31, 2018	$	(77,202)	$	(77,202)
Other comprehensive income (loss) before reclassifications	(5,528		)	—			—			(5,528		)	Other comprehensive income (loss) before reclassifications	(7,337)		(7,337)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	(918		)	—			—			(918		)	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	390		390

Net current-period other comprehensive income (loss)	(6,446		)	—			—			(6,446		)	Net current-period other comprehensive income (loss)	(6,947)		(6,947)
Balance at December 31, 2016	$	(33,712	)	$	—		$	—		$	(33,712	)
Balance at December 31, 2019													Balance at December 31, 2019	$	(84,149)	$	(84,149)



Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans		Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands)							Total
Balance at December 31, 2016	$	(140,155)	$	(5,356)	$	(145,511)
Other comprehensive income (loss) before reclassifications	10,200		—		10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	8,088		317		8,405
Net current-period other comprehensive income (loss)	18,288		317		18,605
Balance at December 31, 2017	$	(121,867)	$	(5,039)	$	(126,906)
Other comprehensive income (loss) before reclassifications	(48,802)		—		(48,802)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	11,772		385		12,157
Reclassification of stranded taxes to retained earnings due to tax reform	(26,233)		(1,100)		(27,333)
Net current-period other comprehensive income (loss)	(63,263)		(715)		(63,978)
Balance at December 31, 2018	$	(185,130)	$	(5,754)	$	(190,884)
Other comprehensive income (loss) before reclassifications	(8,096)		—		(8,096)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	10,118		385		10,503

Net current-period other comprehensive income (loss)	2,022		385		2,407
Balance at December 31, 2019	$	(183,108)	$	(5,369)	$	(188,477)

127

Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps
Changes in AOCI, net of tax
(Dollars in Thousands) Total
Balance at December 31, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 )
Other comprehensive income (loss) before reclassifications (84,955 ) —
—
(84,955 )
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079
1,341
317
9,737
Net current-period other comprehensive income (loss) (76,876 ) 1,341
317
(75,218 )
Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 )
Other comprehensive income (loss) before reclassifications 6,922
—
—
6,922
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,482
686
317
14,485
Net current-period other comprehensive income (loss) 20,404
686
317
21,407
Balance at December 31, 2015 $ (143,877 ) $ —
$ (5,673 ) $ (149,550 )
Other comprehensive income (loss) before reclassifications (5,655 ) —
—
(5,655 )
Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,377
—
317
9,694
Net current-period other comprehensive income (loss) 3,722
—
317
4,039
Balance at December 31, 2016 $ (140,155 ) $ —
$ (5,356 ) $ (145,511 )

Details about the reclassifications out of AOCI (loss) for the years ended December 31, ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively, are as follows:


Puget Energy											Puget Energy
(Dollars in Thousands)											(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)									Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
		2016			2015			2014							2019		2018		2017
Net unrealized gain (loss) and prior service cost on pension plans:											Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,938		$	1,938		$	1,938		Amortization of prior service cost	(a)	$	1,648	$	1,937	$	1,938
Amortization of net gain (loss)	(a)	(525		)	(5,397		)	(519		)	Amortization of net gain (loss)	(a)	(2,142)		(3,431)		(675)
	Total before tax	1,413			(3,459		)	1,419				Total before tax	$	(494)	$	(1,494)	$	1,263
	Tax (expense) or benefit	(495		)	1,211			(496		)		Tax (expense) or benefit	104		314		(442)
	Net of Tax	918			(2,248		)	923				Net of Tax	(390)		(1,180)		821
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives	Purchased electricity	—			(512		)	(572		)
	Tax (expense) or benefit	—			179			200
	Net of Tax	—			(333		)	(372		)
Net unrealized gain (loss) on interest rate swaps:
Interest rate contracts	Interest expense	—			—			(144		)

	Tax (expense) or benefit	—			—			50
	Net of Tax	—			—			(94		)
Total reclassification for the period	Net of Tax	$	918		$	(2,581	)	$	457		Total reclassification for the period	Net of Tax	$	(390)	$	(1,180)	$	821

~~_______________~~


^(a)	~~These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).~~

__________

^(a)These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.


Puget Sound Energy
(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
		2019		2018		2017
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost	(a)	$	1,240	$	1,529	$	1,529
Amortization of net gain (loss)	(a)	(14,048)		(16,430)		(13,972)
	Total before tax	$	(12,808)	$	(14,901)	$	(12,443)
	Tax (expense) or benefit	2,690		3,129		4,355
	Net of tax	$	(10,118)	$	(11,772)	$	(8,088)




Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts	Interest expense	(487)		(487)		(488)
	Tax (expense) or benefit	102		102		171
	Net of Tax	$	(385)	$	(385)	$	(317)
Total reclassification for the period	Net of Tax	$	(10,503)	$	(12,157)	$	(8,405)

____________

128

Puget Sound Energy
(Dollars in Thousands)
Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented
Amount reclassified from accumulated
other comprehensive income (loss)
2016
2015 2014
Net unrealized gain (loss) and prior service cost on pension plans:
Amortization of prior service cost (a) $ 1,529
$ 1,526
$ 1,526
Amortization of net gain (loss) (a) (15,955 ) (22,268 ) (13,954 )
Total before tax (14,426 ) (20,742 ) (12,428 )
Tax (expense) or benefit 5,049
7,260
4,349
Net of tax (9,377 ) (13,482 ) (8,079 )
Net unrealized gain (loss) on energy derivative instruments:
Commodity contracts: Electric derivatives Purchased electricity —
(1,055 ) (2,063 )
Tax (expense) or benefit —
369
722
Net of Tax —
(686 ) (1,341 )
Net unrealized gain (loss) on treasury interest rate swaps:
Interest rate contracts Interest expense (488 ) (488 ) (488 )
Tax (expense) or benefit 171
171
171
Net of Tax (317 ) (317 ) (317 )
Total reclassification for the period Net of Tax $ (9,694 ) $ (14,485 ) $ (9,737 )

~~_______________~~


^(a)	~~These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).~~

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business.


Puget Energy	2019 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,114,839	$	670,930	$	627,007	$	988,354
Operating income	213,460		39,115		26,126		240,307
Net income (loss)	132,154		(32,952)		(39,443)		150,949

Puget Energy 2016 Quarter
(Unaudited; Dollars in Thousands) First
Second
Third
Fourth
Operating revenue $ 962,697
$ 668,169
$ 618,278
$ 915,157
Operating income 284,824
175,634
88,072
236,854
Net income (loss) 141,186
64,553
2,335
104,825


	2018 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,038,008	$	671,852	$	651,464	$	985,172
Operating income	232,785		84,091		37,297		199,885
Net income (loss)	146,897		3,642		(21,970)		107,053


Puget Sound Energy	2019 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,114,839	$	670,930	$	627,007	$	988,354
Operating income	214,159		39,780		26,721		241,955
Net income (loss)	147,302		(8,325)		(15,257)		169,204


	2018 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	1,038,008	$	671,852	$	651,464	$	985,172
Operating income	235,856		81,701		46,147		193,432
Net income (loss)	163,037		26,778		3,891		123,456

129

2015 Quarter
(Unaudited; Dollars in Thousands) First
Second
Third
Fourth
Operating revenue $ 926,835
$ 658,341
$ 605,733
$ 901,791
Operating income 245,235
126,772
69,888
230,030
Net income (loss) 115,676
25,616
(7,928 ) 107,815

Puget Sound Energy 2016 Quarter
(Unaudited; Dollars in Thousands) First
Second
Third
Fourth
Operating revenue $ 962,697
$ 668,169
$ 618,594
$ 915,158
Operating income 281,425
171,991
84,476
237,101
Net income (loss) 156,505
80,900
18,977
124,199

2015 Quarter
(Unaudited; Dollars in Thousands) First
Second
Third
Fourth
Operating revenue $ 926,843
$ 658,341
$ 605,913
$ 902,161
Operating income 240,903
122,753
66,036
226,446
Net income (loss) 129,100
42,699
9,876
122,514

SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY

Puget Energy

Condensed Statements of Income and Comprehensive Income (Loss)

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Non-utility expense and other	$	(1,495)	$	(1,345)	$	(1,466)
Other income (deductions):
Equity in earnings of subsidiary	294,724		320,122		323,568
Non-hedged interest rate swap expense	—		—		28
Interest income	6,643		4,273		1,039
Interest expense	(111,716)		(108,816)		(106,072)
Income tax expense (benefit)	22,552		21,388		(41,903)
Net income (loss)	$	210,708	$	235,622	$	175,194
Comprehensive income (loss)	$	203,761	$	182,702	$	184,624

Year Ended December 31,
2016 2015 2014
Non-utility expense and other $ (5,252 ) $ (1,617 ) $ (5,390 )
Other income (deductions):

Equity in earnings of subsidiary 385,838
309,603
240,102
Non-hedged interest rate swap expense (1,062 ) (3,796 ) (3,915 )
Interest income 2
63
185
Interest expense (104,600 ) (100,114 ) (93,382 )
Income taxes 37,973
37,040
34,235
Net income (loss) 312,899
241,179
171,835
Comprehensive income (loss) $ 306,453
$ 250,956
$ 87,077

See accompanying notes to the condensed financial statements.

130

Puget Energy

Condensed Balance Sheets

(Dollars in Thousands)


	December 31,					December 31,
	2016		2015			2019		2018
Assets:					Assets:
Investment in subsidiaries	$	3,571,550	$	3,415,571	Investment in subsidiaries	$	4,153,618	$	3,820,347
Other property and investments:					Other property and investments:
Goodwill	1,656,513		1,656,513		Goodwill	1,656,513		1,656,513
Current assets:					Current assets:
Cash	397		639		Cash	947		2,067
Receivables from affiliates¹	213		203		Receivables from affiliates¹	180,527		138,714
Total current assets	610		842		Total current assets	181,474		140,781
Long-term assets:					Long-term assets:
Deferred income taxes	309,812		272,487		Deferred income taxes	235,428		221,660
Other	521		537		Other	2,056		2,040
Total long-term assets	310,333		273,024		Total long-term assets	237,484		223,700
Total assets	$	5,539,006	$	5,345,950	Total assets	$	6,229,089	$	5,841,341
Capitalization and liabilities:					Capitalization and liabilities:
Common equity	$	3,688,713	$	3,531,225	Common equity	$	4,000,299	$	3,860,728
Long-term debt	1,808,828		1,783,898		Long-term debt	1,752,644		1,954,205
Total capitalization	5,497,541		5,315,123		Total capitalization	5,752,943		5,814,933
Current liabilities:					Current liabilities:
Account Payable	15,801		171		Account Payable	208		260
Current maturities of long-term debt					Current maturities of long-term debt	450,000		—
Interest	25,523		25,606		Interest	25,938		26,148
Unrealized loss on derivative instruments	141		4,753
Total current liabilities	41,465		30,530		Total current liabilities	476,146		26,408
Long-term liabilities:
Unrealized loss on derivative instruments	—		297
Total long-term liabilities	—		297
Commitments and contingencies
Commitments and contingencies (Note 16)					Commitments and contingencies (Note 16)
Total capitalization and liabilities	$	5,539,006	$	5,345,950	Total capitalization and liabilities	$	6,229,089	$	5,841,341

_______________


¹	~~Eliminated in consolidation.~~

¹Eliminated in consolidation.

See accompanying notes to the condensed financial statements.

131

Puget Energy

Condensed Statements of Cash Flows

(Dollars in Thousands)


	Year Ended December 31,
	2019		2018		2017
Operating activities:
Net cash provided by (used in) operating activities	$	68,724	$	79,176	$	139,005
Investing activities:
Investment in subsidiaries	(210,000)		—		(24,222)
(Increase) decrease in loan to subsidiary	(41,708)		(59,864)		(78,155)
Other	—		—		(437)
Net cash provided by (used in) investing activities	(251,708)		(59,864)		(102,814)
Financing activities:
Dividends paid	(64,220)		(77,204)		(123,307)
Issuance of bond	246,200		209,300		—
Issuance/redemption of term-loan and other long-term debt	—		(150,000)		90,120
Issue costs and others	(116)		(92)		(2,650)
Net cash provided by (used in) by financing activities	181,864		(17,996)		(35,837)
Increase (decrease) in cash	(1,120)		1,316		354
Cash at beginning of year	2,067		751		397
Cash at end of year	$	947	$	2,067	$	751

Year Ended December 31,
2016 2015 2014
Operating activities:
Net cash provided by (used in) operating activities $ 145,719
$ 171,576
$ 225,459
Investing activities:

Investment in subsidiaries —
(28,900 ) —
(Increase) decrease in loan to subsidiary —
28,933
665
Other (6,078 ) (5,632 ) (2,829 )
Net cash provided by (used in) investing activities (6,078 ) (5,599 ) (2,164 )
Financing activities:

Dividends paid (148,965 ) (263,059 ) (223,428 )
Issuance of bond —
400,000
—
Issuance/redemption of term-loan and other long-term debt 12,480
(299,000 ) —
Issue costs and others (3,398 ) (3,341 ) 4
Net cash provided by (used in) by financing activities (139,883 ) (165,400 ) (223,424 )
Increase (decrease) in cash (242 ) 577
(129 )
Cash at beginning of year 639
62
191
Cash at end of year $ 397
$ 639
$ 62

See accompanying notes to the condensed financial statements.

132

NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) Basis of Presentation

Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also hasa wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed onin November ~~29,~~ 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a ~~LNG~~liquefied natural gas (LNG) facility at the Port of Tacoma, Washington. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries.

Equity earnings of subsidiary included earnings from PSE of ~~$380.6~~$292.9 million, ~~$304.2~~$317.2 million and ~~$236.6~~$320.1 million for the years ended December 31, ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of ~~$5.2~~$2.9 million, ~~$5.4~~$4.7 million and ~~$3.5~~$3.9 million for the years ended December 31, ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy.

~~Change in Accounting Principle~~

On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, ~~"Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs"~~. ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 long-term asset financial statement line item “Other” and the liability financial statement line item “Long-term debt” both decreased $15.6 million at Puget Energy.

(2) Long-Term Debt

For information concerning Puget Energy’s long-term debt obligations, see Note 6,7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report.

(3) Commitments and Contingencies

For information concerning Puget Energy’s material contingencies and guarantees, see Note ~~15,~~16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.

133

SCHEDULE II:VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


Puget Energy and Puget Sound Energy (Dollars in Thousands)	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Deductions		Balance at End of Period
Year Ended December 31, 2019
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,408	$	17,633	$	17,747	$	8,294
Year Ended December 31, 2018
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	8,901	$	24,846	$	25,339	$	8,408
Year Ended December 31, 2017
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable	$	9,798	$	26,266	$	27,163	$	8,901

Puget Energy and
Puget Sound Energy
(Dollars in Thousands)
Balance at
Beginning of
Period
Additions
Charged to
Costs and
Expenses
Deductions
Balance
at End
of Period
Year Ended December 31, 2016
Accounts deducted from assets on balance sheet:
Allowance for doubtful accounts receivable $ 9,756
$ 24,389
$ 24,347
$ 9,798
Year Ended December 31, 2015

Accounts deducted from assets on balance sheet:

Allowance for doubtful accounts receivable $ 7,472
$ 20,732
$ 18,448
$ 9,756
Year Ended December 31, 2014

Accounts deducted from assets on balance sheet:

Allowance for doubtful accounts receivable $ 7,385
$ 27,228
$ 27,141
$ 7,472

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

PugetEnergy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, ~~2016~~,2019, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

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

There have been no changes in Puget Energy’s internal control over financial reporting during the ~~year~~quarter ended December 31, ~~2016~~2019, that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Puget Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of Puget Energy’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, Puget Energy’s management concluded that its internal control over financial reporting was effective as of December 31, ~~2016~~.2019.

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Puget Energy’s effectiveness of internal control over financial reporting as of December 31, ~~2016~~2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Puget Sound Energy

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of December 31, ~~2016~~,2019, the end of the period covered by this report. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

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

There have been no changes in PSE’s internal control over financial reporting during the ~~year~~quarter ended December 31, ~~2016~~2019, that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.

In January 2017, PSE implemented a financial systems modernization project designed to improve the financial processes, tools and methods used throughout our business. The modernized systems are being used for transactions in 2017, but were not utilized in preparing 2016 financial information. Management monitored developments related to the financial systems modernization project, including working with the project team to ensure control impacts were identified and documented, in order to assist management in evaluating impacts to internal control. System integration and user acceptance testing were conducted to aid management in its evaluations. Post-implementation reviews of the system implementation and impacted business processes are being conducted to enable management to evaluate the design and effectiveness of internal controls during 2017.

Management’s Report on Internal Control over Financial Reporting

PSE’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Under the supervision and with the participation of PSE’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE’s management assessed the effectiveness of internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, PSE’s management concluded that its internal control over financial reporting was effective as of December 31, ~~2016~~.2019

PSE’s effectiveness of internal control over financial reporting as of December 31, ~~2016~~2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

As of ~~March 2, 2017, ten~~February 21, 2020, twelve directors constitute Puget Energy’s Board of Directors and ~~eleven~~thirteen directors currently constitute PSE’s Board of Directors, as set forth below. The directors are selected in accordance with the Amended and Restated Bylaws of each of Puget Energy and PSE, pursuant to which, the investor-owners of Puget Holdings (the indirect parent company of both Puget Energy and PSE) are entitled to select individuals to serve on the boards of Puget Energy and PSE.

Scott Armstrong, age ~~57,~~60, has been a director on the ~~board~~boards of PSE since June ~~25, 2015.~~of 2015 and on the board of Puget Energy since November 2017. Mr. Armstrong was President and CEO of Group Health Cooperative of Seattle, Washington, a health insurance and medical care provider, positions he had held since January 2005, until its acquisition by Kaiser Permanente on February 1, 2017. An independent director not affiliated with any of the Company’s investors, Mr. Armstrong’s executive leadership experience in a heavily regulated industry that has undergone extensive change, along with his involvement in civic affairs in the Pacific Northwest, are among the reasons for his appointment to the PSE board.

Kenton Bradbury, age 50, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. He is currently the Managing Director of OMERS Infrastructure Management Inc. a position he has held since 2015. Prior to that, Mr. Bradbury served as a director of Infracapital, the infrastructure investment arm of M&G Investments, and served as Senior Vice President of Infrastructure and Regulation at E.ON in Germany. Mr. Bradbury will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

~~Andrew Chapman~~Richard Dinneny, age 57, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Dinneny is currently the Senior Portfolio Manager, Infrastructure and Renewable Resources for British Columbia Investment Management Corporation (BCI) where he has responsibility for all aspects of investing in infrastructure transactions. Mr. Dinneny is a director of Vier Gas Services GmbH & Co. KG, Essen, the owner of Open Grid Europe, German’s leading natural gas transport company. Mr. Dinneny served on the board of Cleco Group LLC, Cleco Corporate Holdings LLC, and Cleco Power LLC. Mr. Dinneny will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

Barbara Gordon, age 61, has been a director on the board of PSE since November 2017. Ms. Gordon currently serves on the Woodland Park Zoo board of directors and as the Vice Chair of the Animal Care Committee. Ms. Gordon previously served as a Vice President of the board of directors for Seattle-King County Habitat for Humanity, a non-profit organization (2016-2018). Prior to that time, Ms. Gordon served as Executive Vice President and Chief Customer Officer of Bellevue-based Apptio, a developer of technology business management software (2016-2017), Senior Vice President and Chief Operating Officer of Isilon/EMC, a digital storage systems company (2013-2016), and as Corporate Vice President of Worldwide Customer Service and Support at Microsoft (2003-2013). An independent director not affiliated with any of the Company's investors, Ms. Gordon brings to the Board her expertise in customer-facing technology initiatives and enterprise level management of customer service and support.

Christopher Hind, age 50, has been a director on the boards of both Puget Energy and PSE since February ~~2009. Mr. Chapman~~28, 2018. He is currently ~~a Managing Director in~~ the ~~Macquarie Capital Funds division of the Macquarie Group,~~Senior Principal, Private Infrastructure with Canada Pension Plan Investment Board (CPPIB), an investment management organization, which position he has held since ~~2006.~~January 2016. Prior to ~~joining the Macquarie Group,~~that, Mr. ~~Chapman was Vice President – Strategy & Regulation for American Water from 2005 to 2006 and Regional~~Hind served as a Managing Director, Investment Banking, at CIBC, a financial institution, from ~~2003~~October 1997 to ~~2004.~~January 2016. Mr. ~~Chapman~~Hind also ~~served~~currently serves on the ~~boards~~board of ~~Cleco Power LLC~~directors of Transportadora de Gas del Peru S.A., the largest transporter of natural gas and ~~Aquarion Water Company.~~natural gas liquids in Peru. Mr. ~~Chapman represents~~Hind was selected by CPPIB and pursuant to the ~~Company’s Macquarie affiliated investors~~Amended and Restated Bylaws of each of the Companies, will serve as an Owner Director on their respective Boards of Directors. Mr. Hind will not receive any director compensation from the Companies for his service as an Owner Director on the boards, in accordance with the terms of the Puget Energy and PSE bylaws, and brings to his service many years of experience in the operational and financial management challenges specific to regulated utilities.Boards, but will be reimbursed for out-of-pocket expenses.

~~Kimberly Harris~~

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Steven W. Hooper, age ~~52, is~~66, has been a director on the boards of both Puget Energy and PSE which positions she has held since March 1, 2011. Ms. Harris has also been President and Chief Executive Officer since March 1, 2011. Prior to that time, Ms. Harris served as President from July 2010 through February 2011. Ms. Harris also served as Executive Vice President and Chief Resource Officer from May 2007 until July 2010, and was Senior Vice President Regulatory Policy and Energy Efficiency from 2005 until May 2007. Ms. Harris is currently on the board of directors of U.S. Bancorp, a bank holding company.

~~Steven W. Hooper, age 63, is a director on the boards of both Puget Energy and PSE, which positions he has held~~ since January 2015. Mr. Hooper is currently co-founder and partner of Ignition Partners, a venture capital firm that focuses on technology based in Bellevue, Washington, which position he has held since 2000. Previously, Mr. Hooper was the co-CEO of Teledesic (1998-2000) and CEO of Nextlink (1997-1998) and AT&T Wireless (1994-1997). Mr. Hooper also currently serves on the boards of directors of Recreational Equipment, Inc. (REI), an outdoor equipment company, and Airbiquity, Inc. ~~and Blucora, Inc.~~, an automotive telematics company, as well as on the boards of various Ignition Partners portfolio companies. An independent director not affiliated with any of the Company’s investors, Mr. Hooper’s leadership skills, experience with the challenges facing regulated businesses, and involvement with regional educational and civic organizations are some of the reasons that led to his appointment to the Puget Energy and PSE boards.

~~Karl Kuchel~~Tom King, age 3858, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. King is currently the Operating Executive with AEA investors, a middle market private equity firm, which position he has held since ~~January 2017,~~2017. Mr. King served as Chairman and President of National Grid U.S. from 2007-2015. Prior to that, he was president of PG&E Corporation and Chairman and CEO of Pacific Gas and Electric from 2003-2007. Mr. King serves on the board of Entregado Group and Allied Power Group and served on the board of Peak Reliability and EnergySavvy, Inc. Mr. King serves on the boards of Puget Energy and PSE as a representative of CPPIB’s ownership interests, pursuant to the ~~Company’s Macquarie affiliated investors and FSS Infrastructure Trust, consistent with~~terms of the Puget Energy and PSE bylaws. Mr. Kuchel is currently the Chief Executive Officer of Macquarie Infrastructure Partners, Inc., which position he has held since June 2016. Prior to that time, Mr. Kuchel served as Chief Operating Officer (from November 2010 through May 2016) of Macquarie Infrastructure Partners, Inc. Mr. Kuchel also currently serves on the boards of directors of various other portfolio companies managed and advised by Macquarie Infrastructure Partners, Inc., and provides the Puget Energy and PSE boards the benefit of his experience managing and overseeing the financial and operational affairs of infrastructure owners.

~~Christopher Leslie~~Mary Kipp, age 52, has been a director on the boards of both Puget Energy and PSE ~~since February 2009, as a representative of the Company’s Macquarie affiliated investors consistent with the Puget Energy~~effective January 3, 2020. Ms. Kipp has also been elected President and PSE bylaws. Mr. Leslie is currently an Executive Director of Macquarie Group Limited, which position he has held since 2005, President of Macquarie Infrastructure and Real Assets Inc., and since 2006 Chief Executive ~~Officer of Macquarie Infrastructure Partners Inc. Mr. Leslie also serves as a director on the board of Cleco Power, LLC. In addition to his management~~officer since January 3, 2020, and ~~banking skills, Mr. Leslie provides the Puget Energy and PSE boards the benefit of his experience with electric utilities, gas distribution systems and other aspects of the infrastructure sector.~~

~~David MacMillan~~, age 64, has been a director on the boards of both Puget Energy and PSE since November 6, 2012. Mr. MacMillan currently is a non-executive director of Viridian Group Ltd., an energy company based in Northern Ireland, and serves on the boards of Potentia Solar Inc. and Eagle Creek Renewable Energy, LLC. He has also served as managing director and senior advisor to Good Energies Capital (now named Bregal Energy), a New York-based private equity fund focused on the renewable energy sector, which positions he held from 2007 to 2010, non-executive director of Ontario Power Generation (from 2004 to 2012) and Intergen (from 2006 to 2008). Mr. MacMillan serves on the boardswas President of Puget Energy and PSE from August 2019 to December 2019. Prior to that time Ms. Kipp served as ~~a representative~~President, Chief Executive Officer and Director of ~~Canada Pension Plan Investment Board (CPPIB)'s ownership interests, pursuant~~El Paso Electric Company (El Paso) from May 2017 to ~~the terms~~August 2019. Prior to that she served as Chief Executive Officer and director of ~~the Puget Energy~~El Paso from December 2015 to May 2017, and ~~PSE bylaws,~~President of El Paso from 2014 to 2015. Ms. Kipp also served as Senior Vice President, General Counsel and ~~brings~~Chief Compliance Officer at El Paso from 2010 to ~~this service his skills in project finance and experience with managing the capital requirements of energy companies.~~2014.

Paul McMillan,age ~~62,~~65, has been a director on the boards of both Puget Energy and PSE since April 23, 2015. Mr. McMillan is currently principal of Tidal Shift Capital Inc., which provides consulting and project development services to energy and infrastructure clients, of Toronto, Ontario, Canada, which position he has held since July 2009. He served as Senior Vice President of EPCOR Energy Division of Edmonton, Alberta, Canada, from May 2005 to July 2009 and President of EPCOR Merchant and Capital LP from September 2000 to May 2005. ~~In addition, Mr. McMillan is on the board of BluEarth Renewables.~~ Mr. McMillan serves on the boards of Puget Energy and PSE as a representative of Aimco’s ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his experience in energy and gas operations and trading as well as renewable and gas project development.

Mary McWilliams, age ~~68,~~71, has been a director on the boards of both Puget Energy and PSE since March 1, 2011. Ms. McWilliams was most recently the Executive Director at Washington Health Alliance, a health care organization, which position she held from 2008 to 2014. She also served as President and Chief Executive Officer at Regence BlueShield from 2000 to 2008. In addition, Ms. McWilliams serves as a Board member of the Virginia Mason Health System, a health care services organization. Her civic commitments have included Seattle Rotary, Seattle Symphony, YWCA and ~~Business Health Trust.~~the Greater Seattle Chamber of Commerce. Ms. ~~McWilliams’s~~McWilliams’ significant experience managing consumer-focused organizations with challenging regulatory and compliance regimes, her civic involvement in the community, as well as her extensive knowledge of the western Washington economy, generally, are some of the reasons that led to her appointment to the Puget Energy and PSE boards on behalf of the CPPIB.

~~Etienne Middleton~~Christopher Trumpy, age 42, has been a director on the boards of both Puget Energy and PSE since March 1, 2016. Mr. Middleton is currently the Senior Principal, Private Infrastructure with CPPIB, which position he has held since 2009. Mr. Middleton serves on the boards of Puget Energy and PSE as a representative of CPPIB's ownership interests, pursuant to the terms of the Puget Energy and PSE bylaws, and brings to this service his skills in financial management of infrastructure providers. Mr. Middleton also serves on the boards of Transelec S.A., a Chilean transmission company, and Grupo Costanera, a Chilean toll-road operator.

~~Christopher Trumpy, age 62,~~65, has been a director on the boards of both Puget Energy and PSE since January 12, 2010. Mr. Trumpy is currently a consultant at Circle Square Solutions, a policy and governance consulting firm, which position he has held since 2013. He served as the Chairman of the Pacific Carbon Trust from 2008 to 2013. He also served as Chairman of the British Columbia Investment Management Corporation (or ~~bcIMC)~~BCI) from 2000 to 2008. In addition, Mr. Trumpy served as Deputy Minister at Ministries of Finance, Environment and Provincial Revenue from 1998 to 2009. Mr. Trumpy represents the ownership stake in the Company of ~~bcIMC,~~BCI, in accordance with the terms of the Puget Energy and PSE bylaws, and provides the boards the benefit of his significant leadership roles in government and policy-making, among other attributes.

Martijn Verwoest, age 43, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Verwoest is currently the Head of Energy & Utilities at Stichting Pensioenfonds Zorg en Welzijn (PGGM), and is a member of their Infrastructure Investment Committee since 2007. From 2001 to 2007, he worked in PGGM’s public equity department. Mr. Verwoest will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

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Steven Zucchet, age 54, has been a director on the boards of both Puget Energy and PSE effective April 17, 2019. Mr. Zucchet is currently the Managing Director at Ontario Municipal Employees Retirement System Infrastructure Management (OMERS). Since joining OMERS in 2003, Mr. Zucchet has led numerous transactions and had asset management responsibilities at a number of utility and generation companies in Canada and the United States. He is currently on the board of Oncor and Bruce Power Inc. Mr. Zucchet will not receive any director compensation from the Companies for his service as an Owner Director on the Boards, but will be reimbursed for out-of-pocket expenses.

Executive Officers

The information required by this item with respect to Puget Energy and PSE is incorporated herein by reference to the material under “Executive Officers of the Registrants” in Part I of this report.

Audit Committee

The Puget Energy and PSE Boards of Directors have both established an Audit Committee. Directors ~~Andrew Chapman,~~Kenton Bradbury, Richard Dinneny, Steven Hooper, ~~David MacMillan~~Paul McMillan and ~~Paul McMillan~~Tom King are the members of the Audit Committee. The Board has determined that ~~Andrew Chapman~~Paul McMillan meets the definition of “Audit Committee Financial Expert” under United States Securities and Exchange Commission (SEC) rules. Puget Energy and PSE currently do not have any outstanding stock listed on a national securities exchange and, therefore, there are no independence standards applicable to either company in connection with the independence of its Audit Committee members.

~~Changes to the~~ Procedures by which Shareholders may recommend Nominees to the Board of Directors

There have been no material changes to the procedures by which shareholders may recommend nominees to the Boards of Directors of Puget Energy and PSE. Members of the Boards of Directors of Puget Energy and PSE are nominated and elected in accordance with the provisions of their respective Amended and Restated Bylaws.

Code of ~~Ethics~~Conduct

Puget Energy and PSE have adopted a Corporate Ethics and Compliance Code applicable to all directors, officers and employees and a Code of Ethics applicable to the Chief Executive Officer and senior financial officers, which are available on the website www.pugetenergy.com. If any material provisions of the Corporate Ethics and Compliance Code or the Code of Ethics are waived for the Chief Executive Officer or senior financial officers, or if any substantive changes are made to either code as they relate to any director or executive officer, we will disclose that fact on our website within four business days. In addition, any other material amendments of these codes will be disclosed.

~~Additional Information~~

Communications with the Board

Interested parties may communicate with an individual director or the Board of Directors as a group via U.S. Postal mail directed to: Chairman of the Board of Directors, c/o Corporate Secretary, Puget Energy, Inc., P.O. Box 97034, ~~PSE-12,~~EST-11, Bellevue, Washington 98009-9734. Please clearly specify in each communication the applicable addressee or addressees you wish to contact. All such communications will be forwarded to the intended director or Board as a whole, as applicable.

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ITEM 11. EXECUTIVE COMPENSATION

Puget Energy

Puget Sound Energy

Executive Compensation

Compensation and Leadership Development Committee Interlocks and Insider Participation

The members of the Compensation and Leadership Development Committee (referred to as the Committee) of the Boards of Directors (referred to as the Board) of Puget Energy and PSE (referred to as the Company) are named in the Compensation and Leadership Development Committee Report. No members of the Committee were officers or employees of the Company or any of its subsidiaries during ~~2016,~~2019, nor were they formerly Company officers or had any relationship otherwise requiring disclosure. Each member meets the independence requirements of the SEC and the New York Stock Exchange (NYSE).

Compensation Discussion and Analysis

This section provides information about the compensation program for the Company’s Named Executive Officers who are included in the Summary Compensation Table below. For ~~2016~~2019, the Company’s Named Executive Officers and titles were:

•Kimberly J. Harris, President and Chief Executive Officer (CEO); until August 30, 2019, and CEO until her retirement effective January 2, 2020;

•Mary E. Kipp, President, effective August 30, 2019, and President and CEO, effective January 3, 2020;

•Daniel A. Doyle, Senior Vice President and Chief Financial Officer (CFO);

•Steve R. Secrist, Senior Vice President, General Counsel, Chief Ethics and Compliance Officer; and

•Marla D. Mellies, Senior Vice President, Chief Administrative ~~Officer; and~~Officer.

•~~Philip K. Bussey, Senior Vice President, Chief Customer Officer~~

This section also includes a discussion and analysis of the overall objectives of our compensation program and each element of compensation the Company ~~provides.~~provides to its Named Executive Officers.

Compensation Program Objectives

The Company’s executive compensation program has two main objectives:

•Support sustained Company performance by attracting, retaining and motivating talented people to run the business.

•Align incentive compensation payments with the achievement of short and long-term Company goals.

The Committee is responsible for developing and monitoring an executive compensation program and philosophy that achieves the foregoing objectives. In performing its duties, the Committee obtains information and advice on various aspects of the executive compensation program from its independent executive compensation consultant, ~~Frederic W. Cook & Co., Inc. (Cook & Co.)~~Meridian Compensation Partners, LLC (Meridian). The Committee recommends to the ~~full~~ Board for approval both the salary level for our CEO, based on information provided by ~~Cook & Co.,~~Meridian and other relevant factors described below, and the salary levels for the other executives, based on recommendations from our CEO. The Committee also recommends to the Board for ~~its~~ approval the annual and long-term incentive compensation plans for the executives, the setting of performance goals and the determination of target and actual awards under those ~~plans.~~plans, based on the compensation philosophy and taking into consideration information provided by Meridian and other relevant factors.

In ~~2016,~~2019, the ~~Committee~~Company used the following strategies to achieve the objectives of our executive compensation program:

•Design and deliver a competitive total compensation opportunity. To attract, retain and motivate a talented executive team, the ~~Committee~~Company believes that total pay opportunity should be competitive with companies of similar size, revenue, industry and scope of ~~operations so that new executives will want to join the Company and current executives will be retained.~~operations. As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee, with the support of Meridian, annually compares executive compensation levels to external market data from similar companies in our industry and targets each element of target total direct compensation ~~(the sum of base~~(base salary and target annual and long-term incentive award opportunities) to the 50th percentile of the market data with variations by individual executive, as appropriate.During 2019, the Committee worked with Meridian to develop a compensation package for the new President, and now President and CEO, Mary Kipp, who succeeded Ms. Harris. The ~~Committee~~terms of Ms. Kipp’s compensation are described below.The Company also

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recognizes the importance of providing retirement income. ~~Executives choose to work for~~As such, the ~~Company as opposed to a variety of other alternative organizations, and one financial goal of employees is to provide a secure future for themselves and their families. The~~ Committee reviews ~~the design of~~our retirement programs ~~provided by our comparator group~~ and provides benefits that are ~~commensurate~~competitive with ~~this group.~~

our peers.

•Place a significant portion of each executive’s target ~~total~~incentive compensation at risk to align executive compensation with Company financial and operating performance. Under its “pay for performance” philosophy, the ~~Committee works to design and deliver~~Company maintains an incentive compensation program that supports the Company’s business ~~direction as approved by the Board~~strategy and aligns executive interests with those of investors and customers. The Committee believes that a significant portion of each executive’s compensation should be “at risk” and ~~rewarded~~earned based on achievement relative to annual and long-term performance goals. For example, Ms. Harris, CEO in 2019, had a mix of 2019 cash compensation comprised of 22% base salary and 78% at-risk target compensation. By establishing goals, monitoring results, and rewarding achievement of goals, the Company ~~focuses~~seeks to focus executives on actions that will improve the Company and enhance investor value, while also retaining key talent. The Committee annually evaluates and establishes the performance ~~factors~~goals and targets for our annual and long-term incentive programs and considers adjustments as appropriate to meet the objectives of our executive compensation program. As described under “Risk Assessment,” the Company’s policies and practices surrounding incentive pay are structured in a manner to mitigate the risk that employees would seek to take untoward risks in an attempt to increase incentive results.

•Oversee the Company’s talent management process to ensure that executive leadership continues uninterrupted by executive retirements or other personnel changes. The CEO leads talent reviews for leadership succession planning through meetings and discussions with her executive team. Each executive conducts talent reviews of senior employees that report to him or her and who have high potential for assuming greater responsibility in the Company. Utilizing evaluations and assessments, the Committee and the Board annually review these assessments of executive readiness, the plans for development of the Company’s key executives, and progress made on these succession plans. The Committee and the Board directly participate in discussion of succession plans for the position of CEO. As part of its ongoing succession planning efforts, during 2019, the Committee and the Board executed a CEO succession plan pursuant to which Ms. Kipp became CEO effective January 2020.

Compensation Philosophy

The target total compensation package is designed to provide participants with appropriate incentives that are competitive with the comparator group described below and motivate the achievement of current operational performance and customer service goals as well as the long-term objective of enhancing investor value. The Company does not have a specific policy regarding the mix of compensation elements, although long-term incentive awards comprise the largest portion of each executive’s incentive pay. The Company arrives at a mix of pay by setting each compensation element relative to market comparators. The Company delivered cash compensation to the Named Executive Officers in 2019 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the alignment with investors.

As a matter of philosophy, all three components of target total direct compensation are generally targeted at the 50th percentile of industry practice, with deviations by individual executive as described below. If Company performance results are below expectations, actual compensation is expected to be below this targeted level. If Company performance exceeds target, actual compensation is expected to be above this targeted level.

Individual pay adjustments are reviewed annually to see how they position the executive relative to the 50th percentile of market pay, while also considering other factors such as, the executive’s recent performance, experience level, company performance, retention and internal pay equity. Notwithstanding the median philosophy, the Company may choose to target an executive’s compensation above or below the 50th percentile of market pay when that individual has a role with greater or lesser responsibility than the best comparison job or when our executive’s experience and performance differ from those typically found in the market.

Role of Market Data

The Company uses market data compiled by Meridian to inform its pay decisions on base salary, target annual incentives and target long-term incentive awards. Market data is obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation benchmarking peer group. The market survey data were sourced from a select cut from the Willis Towers Watson 2018 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 22 companies in the custom market survey cut used to inform target compensation decisions for 2019 are shown below:

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Custom Survey Peer Group
1.	Alliant Energy	10.	Hawaiian Electric Industries, Inc.	19.	Spire, Inc.
2.	Ameren	11.	NiSource	20.	Vectren
3.	Atmos Energy	12.	OGE Energy	21.	WEC Energy Group
4.	Avangrid	13.	ONE Gas, Inc	22.	Westar Energy
5.	Avista	14.	Pinnacle West Capital
6.	Black Hills	15.	PNM Resources
7	CMS Energy	16.	Portland General Electric
8	Eversource Energy	17.	SCANA
9.	Great Plains Energy	18.	Southwest Gas

The market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 16 companies, all but one of which overlapped with companies included in the market survey data. The 2018 median revenue of the executive compensation peers was $3.6 billion, which was comparable to PSE’s annual revenues of $3.4 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2019 compensation decisions are the same as those used for 2018 and are shown below:


Proxy Peer Group
1.	Alliant Energy	7.	Great Plains Energy	13.	SCANA
2.	Ameren	8.	MDU Resources Group	14.	Vectren
3.	Avista	9.	NiSource	15.	WEC Energy
4.	Black Hills	10.	OGE Energy	16.	Westar Energy
5.	CMS Energy	11.	Pinnacle West Capital
6.	Eversource Energy	12.	Portland General Electric

Compensation Program Elements

The Company’s executive compensation program encompasses a mix of base salary, annual and long-term incentive compensation, retirement programs, health and welfare benefits and a limited number of perquisites. The Company also provides certain post-termination and change in control benefits to executives who were employed by the Company prior to March ~~2009.~~2009 under certain legacy arrangements. Since the Company is not publicly listed and does not grant equity awards to its executives, it relies on a mix of ~~non-equity~~fixed and variable cash-based compensation elements to achieve its compensation ~~objectives.~~

~~The target total compensation package is designed to provide participants with appropriate incentives that are competitive with~~objectives, including a performance unit plan, which helps align the ~~comparator group described below and drive the achievement~~interests of current operational performance and customer service goals as well as the long-term objective of enhancing investor value. The Company does not have a specific policy regarding the mix of compensation elements, although long-term incentive awards comprise the largest portion of each executive’s incentive pay. The Company arrives at a mix of pay by setting each compensation element relative to market comparators. The Company delivered cash compensation to the Named Executive Officers ~~in 2016 through base salary to provide liquidity for the executives and through incentive programs to focus performance on important Company goals and to increase the alignment~~ with those of investors.

~~Review of Pay Element Competitiveness~~

To help inform the Committee’s recommendations for 2016 base salaries, annual incentive programs and long-term incentive programs, the Committee reviewed market data obtained from both industry-specific surveys and proxy statements of public companies selected for inclusion in the Company’s custom executive compensation benchmarking peer group. The market survey data were sourced from a select cut from the Towers Watson 2015 Energy Services Survey, comprised of utility and other companies similar in size and scope of operations to PSE. The 24 companies in the custom market survey cut used to inform target compensation decisions for 2016 are:

Custom Survey Peer Group
1. AGL Resources 10. MDU Resources Group 19. Teco Energy
2. Alliant Energy 11. NiSource 20. UIL Holdings
3. Ameren 12. OGE Energy 21. UNS Energy
4. Atmos Energy 13. Oncor Electric Delivery 22. Vectren
5. Avista 14. Pinnacle West Capital 23. Westar Energy
6. Black Hills 15. PNM Resources 24. Wisconsin Energy
7. CMS Energy 16. Portland General Electric
8. CPS Energy 17. SCANA
9. LLG&E and KU Energy 18. Southwest Gas

As noted, the market survey data were supplemented with proxy statement data for select positions in the Company’s executive compensation peer group, which was comprised of 14 companies, all but four of which overlapped with companies included in the market survey data. The 2015 median revenue of the executive compensation peers was $3.6 billion, which was comparable to PSE’s annual revenues of $3.0 billion at the time the peer group was developed. The peer companies included in the Company’s executive compensation benchmarking peer group to inform 2016 compensation decisions are shown below:

Proxy Peer Group
1. Alliant Energy 6. MDU Resources Group 11. SCANA
2. Avista 7. NiSource 12. Vectren
3. Eversource Energy 8. Pepco Holdings 13. Westar Energy
4. Great Plains Energy 9. Pinnacle West Capital 14. Wisconsin Energy
5. Integrys Energy Group 10. Portland General Electric

As a matter of philosophy, all three components of target total direct compensation are generally targeted at the 50th percentile of industry practice, with deviations by individual executive as described below. If Company performance results are below expectations, actual compensation is expected to be below this targeted level and if Company performance exceeds target, actual compensation is expected to be above this targeted level.

Individual pay adjustments are reviewed annually to see how they position the executive in relation to the 50th percentile of market pay, while also considering the executive’s recent performance and experience level. Despite the median philosophy, the Company may choose to target an executive’s compensation above or below the 50th percentile of market pay when that individual has a role with greater or lesser responsibility than the best comparison job or when our executive’s experience and performance exceed those typically found in the market. In addition to the foregoing market data, the Committee generally also received advice from Cook & Co. in connection with 2016 compensation decisions.

Base Salary

We recognize that it is necessary to provide executives with a fixed amount of regularly paid compensation that ~~is delivered each month and~~ provides a balance to other pay elements that are at risk. ~~As mentioned above, base~~Base salaries are reviewed annually by the Committee based on its median philosophy, internal pay equity considerations and considerations specific to an individual ~~executive considerations~~ such as an executive’s expertise, level of performance achievement, experience in the role and contribution relative to others in the organization.

Base Salary Adjustments for ~~2016~~2019

The Committee reviewed the base salaries of the Named Executive Officers in early ~~2016~~2019 and recommended base salary adjustments to the Board. The Board approved the Committee’s ~~recommendation to increase executive salaries as~~salary recommendations shown in the table below. The adjustments were effective March 1, ~~2016.~~2019. Base salaries for ~~2016~~2019 generally remained at the 50th percentile of market among the comparator group. The annual salary for Ms. Harris ~~is unchanged from 2015, given that her current base salary was slightly higher than~~aligns with the ~~50th percentile of~~ market ~~among the survey peer group.~~median. The salary increase percentages approved by the Board for ~~the other Named Executive Officers~~Mr. Doyle and Mr. Secrist were ~~approximately 3%,~~ similar to salary increases for other non-represented employees, ~~except for Mr. Secrist who~~and Ms. Mellies received an ~~additional~~ adjustment to better align with the market ~~levels.~~level. For Ms. Kipp, who joined the Company as President in August 2019, the Committee recommended and the Board approved a base salary consistent with the market level for her position.

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Name	2015 Base Salary	2016 Base Salary	% Change	Name	2018 Base Salary	2019 Base Salary	% Change
Kimberly J. Harris	$900,000	$900,000	—%	Kimberly J. Harris	$950,000	$1,000,000	5%
Mary E. Kipp				Mary E. Kipp	n/a	860,000	n/a
Daniel A. Doyle	496,501	511,396	3	Daniel A. Doyle	521,000	531,420	2
Steve R. Secrist	362,923	388,327	7	Steve R. Secrist	445,000	462,800	4
Marla D. Mellies	299,763	308,755	3	Marla D. Mellies	360,000	392,400	9
Philip K. Bussey	297,583	306,510	3

~~2016~~2019 Annual Incentive Compensation

All PSE employees, including the Named Executive Officers, are eligible to participate in an annual incentive program referred to as the “Goals and Incentive Plan.” The plan is designed to ~~provide financial incentives for achieving~~incent our employees to achieve desired annual operating results, measured by EBITDA, ~~while also meeting~~and meet the Company’s service quality commitment to customers, a reliability measure (non-storm outage duration—System Average Interruption Disruption Index-- or “SAIDI”) and an employee safety measure. EBITDA was selected as a performance goal because it provides a financial measure of cash flows generated from the Company’s annual operating performance.Target incentive opportunities under the plan are based on a percentage of an employee’s base salary.

For ~~2016,~~2019, the Company’s service quality commitment was measured by performance against ~~nine~~eight Service Quality Indicators (SQIs) covering three broad categories, set forth below. These are the same SQIs for which the Company is accountable to the Washington Commission. ~~Annual incentive funding is decreased if a SQI is not achieved.~~ The Company's annual report to the Washington Commission and our customers describes each SQI, how it is measured, the Company’s required level of achievement, and performance results. The Company’s service quality report cards are available at http://www.PSE.com/PerformanceReportCards.

The SQIs for ~~2016~~2019 were the same as those in ~~2015~~2018 and were as follows:

•Customer Satisfaction (3 SQIs) - Customer satisfaction with the ~~telephone access~~customer care center, ~~and~~ natural gas field services and number of Washington Commission complaints.

•Customer Service ~~(2 SQIs)~~ (1 SQI)- Calls answered “live” ~~and on-time appointments.~~within 60 seconds by customer care center.

~~Safety and Reliability~~•Operations Services (4 SQIs)- Gas emergency response, electric emergency response, non-storm outage frequency, and ~~non-storm outage duration.~~

on-time appointments.

In ~~2016,~~2019, the Company ~~retained~~began measuring SAIDI according to a scale based on improvement compared to a five-year average, with the measure for 2019 being 159 minutes.

The employee safety performance measure in the annual incentive plan funding ~~to promote its~~reflects the Company’s continued commitment to employee safety.The safety performance measure contains three targets which must all be satisfied for the safety measure to be treated as met.The three targets for 2019 were:

•All employees attend a monthly safety “meeting in a box” presentation or complete the same content online.The target completion rate is no less than 95%.

•The Company DART (Days Away from Work, days of Restricted Work, or Job Transfer) not to exceed a rate of 0.49

•All employees complete two modules of a PSE Athlete training program.The target completion rate is no less than 95%.

Annual incentive funding is decreased if a SQI is not achieved. The employee safety measure ~~functions~~and SAIDI function similarly to the ~~nine~~eight SQIs in determining the funding of the annual incentive plan. That is, if the safety measure or SAIDI is not achieved, annual incentive funding will be decreased by 10%, in the same way as a missed SQI. ~~The safety performance measure contains four targets which must all be satisfied for the safety measure to be treated as met. The four targets for 2016 were:~~

~~All employees attend a monthly safety “meeting in a box” presentation, or complete the same content online. The target completion rate is no less than 95%.~~

~~The Company DART (~~D~~ays~~ A~~way from Work, days of~~ R~~estricted Work, or Job~~ T~~ransfer) not to exceed a rate of 0.52 in 2016.~~

~~Field employees to attend the Industrial Athlete program, a new training designed to improve mobility and strengthen stability. The target completion rate is no less than 95% of field employees.~~

~~Office employees to complete an on-line training to increase knowledge and skill in CPR and First Aid. The target completion rate is no less than 95% of office employees.~~

In ~~2016,~~2019, 100% funding for the annual incentive plan required (i) achievement of 10 out of 10 customer service and safety measures (all ~~nine~~eight SQIs, SAIDI and achievement of the safety measure) and (ii) target EBITDA performance.All 10 customer service ~~and safety~~ measures were ~~met.~~

~~Funding levels~~met for ~~2016~~2019, but the safety measure was not met, and EBITDA finished at ~~maximum, target, and threshold are shown in the table below:~~

Annual Incentive Performance Payout Scale and Actual Performance
Performance 2016 EBITDA (In Millions) SQI & Safety* Funding Level
Maximum $ 1,688.0
10/10 200 %
Target 1,250.0
10/10 100
Threshold 1,125.0
6/10 30
2016 Actual Performance $ 1,255.3
10/10 102 %

~~_______________~~


^*	Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,125 million are required for any annual incentive payout funding. SQI/Safety results below 10/10 reduce funding (e.g., 9/10 = 90%, 8/10 = 80%, 7/10 = 70%).

The Committee can adjust EBITDA used in the annual incentive calculation to exclude nonrecurring items that are outside the normal course of business for the year. For 2016, the Committee adjusted the level of EBITDA at target lower by $1.1 million to reflect the additional 2016 incentive paid based on 2015 SQI results (see section below “2015 Annual Incentive Review during 2016”) and keep the 2016 EBITDA performance at the same percentage96.4% of target, ~~that would have applied absent the payment.~~ so funding was less than 100%, as described further below.

Individual awards may be adjusted upward or downward based on an evaluation of an executive officer’s performance against individual and team goals that align with the corporate goals described below.

~~2016~~2019 Corporate Goals

In ~~2016,~~2019, the Company continued using the Integrated Strategic Plan (ISP) to summarize for employees the direction and overall goals of the Company. The plan has five objectives which capture our ~~2016~~2019 corporate goals and which have been

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communicated to our employees. Each employee, including the Named Executive Officers, has specific individual and team goals linked to driving strategies that meet one or more of the following ISP objectives:

•Safety - Our ~~Safety Objective~~safety objective is our foundation: If ~~Nobody Gets Hurt Today,~~nobody gets hurt today, we will feel safe and secure and be able to perform at our best.

•People - When we’re ~~Safe,~~safe, we can achieve our ~~People Objective~~people objective of being a ~~Great Place~~great place to ~~Work,~~work, with engaged employees who live our values, embrace an ownership culture and are motivated to drive results for our company and our customers.

•Process and Tools - Engaged employees take us to our ~~Process~~process and ~~Tools Objective~~tools objective where results start with achieving ~~Operational Excellence,~~operational excellence, with continuous improvement of our internal processes and tools so that we can increase efficiency, eliminate waste, improve reliability and enhance customer service.

•Customer- We now have the fundamentals to achieve our ~~Customer Objective~~customer objective of delivering greater value and being our ~~Customer’s Energy Partner~~customer’s energy partner of ~~Choice~~choice in a competitive marketplace.

•Financial - Being our customer’s energy partner of choice takes us to our ~~Financial Objective~~financial objective of increasing our ~~Financial Strength,~~financial strength, allowing us to sustain further improvement.

~~2015 Annual Incentive Review During 2016~~

In March 2016, the Company paid annual incentive awards based on 2015 EBITDA performance of $1,222.2 million (98.9% of target performance) and 8/10 Safety/SQI goals met, for an overall funding level of 75.6% of target, as described in the Company’s 2015 Form 10-K. The Company filed for an exception with the Washington Commission for the SQI goal of System Average Interruption Disruption Index (SAIDI), due to extraordinary storm activity during August and November 2015. On May 12, 2016, the Company received approval to exclude the extraordinary storm activity, resulting in the SQI having been deemed met. With 9/10 Safety/SQI goals met in 2015, the funding for annual goals and incentives would have increased to 84.7% of target. In light of the approval from the Washington Commission, the Board approved an additional payment in 2016 based on the impact from the SQI being deemed met. Accordingly, employees who received an annual incentive in 2015 and are eligible to receive an annual incentive in 2016 will be paid this additional amount in March 2017. For the Named Executive Officers, these amounts are included in the “Bonus” column of the 2016 Summary Compensation Table.

~~2016~~2019 Annual Incentive Plan Results

~~Achievement~~For 2019, achievement of the corporate goals ~~for 2016~~under the annual incentive plan was at ~~100.4%~~96.4% of target for EBITDA, and ~~fully~~9/10 measures met for SQI, safety, and ~~safety~~SAIDI achievement. PSE EBITDA was ~~$1,255.3~~$1,293.2 million, and SQI, SAIDI and safety achievement was 109 out of 10, leading to a funding level for ~~2016~~2019 of ~~102%~~74.0% for the annual incentive ~~plan.~~plan for the named executive officers.

Funding levels for 2019 at maximum, target, and threshold are shown in the table below:


Annual Incentive Performance Payout Scale and Actual Performance
Performance Measure (Dollars in Millions)	2019 EBITDA				SQI, SAIDI& Safety*	Funding Level
Maximum		$	1,810.4	10/10	200%
Target		1,341.0		10/10	100
Threshold		1,206.9		6/10	30
2019 Actual Performance		$	1,293.2	9/10	74.0%

_______________

* Combined SQI, SAIDI & Safety results of 6/10 or better and minimum EBITDA of $1,206.9 million are required for any annual incentive pay out funding

SQI Safety results below 10/10 reduce funding (e.g., 9/10=90%, 8/10=80%, 7/10=70%)

For ~~2016,~~2019, individual target incentive levels for the annual incentive plan varied by executive officer as a percentage of ~~2016~~2019 base salary as shown in the table below, based on the executive’s level of responsibility within the Company and informed by market data. Target annual incentive opportunities as a percentage of base salary for the Named Executive Officers ~~remained~~were unchanged from ~~2015 levels.~~2018 levels, except for Ms. Kipp who joined the Company in 2019 and whose target annual incentive opportunity was set at 90% of base salary. No bonus is earned unless at least threshold EBITDA and SQI goals are achieved. The achievement of threshold performance results in a 30% of target bonus payout. The maximum incentive payable for exceptional performance in this plan is ~~twice the~~two times each Named Executive Officer's target incentive.

An executive’s individual award amount can be increased or decreased based on an assessment by the CEO (or the Board in the case of the CEO) of the executive’s individual and team performance results. After considering performance on individual and team goals, ~~which were determined to be met or exceeded by each executive,~~ adjustments were made by the CEO for individual performance of certain Named Executive Officers below CEO in ~~2016. In recognition of the achievement of individual goals and the Company's financial performance, the Committee similarly recommended an award adjustment for the CEO in 2016.~~2019. The adjustments for individual performance are noted in the "Bonus" column on the Summary Compensation table and did not materially change the amounts resulting from ~~2016~~2019 achievement of the corporate goals. The Board approved the incentive amounts shown below, which will be paid in March ~~2017:~~2020:

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Name	Target Incentive (% of Base Salary)	2016 Actual Incentive Paid		2016 Actual Incentive (% of Base Salary)		Name		Target Incentive (% of Base Salary)	2019 Actual Incentive Paid			2019 Actual Incentive (% of Base Salary)
Kimberly J. Harris	100%	$	1,101,600	122	%	Kimberly J. Harris		100%	$	740,000		74%
Mary E. Kipp						Mary E. Kipp		90*	190,920			67*
Daniel A. Doyle	45	234,731		46		Daniel A. Doyle	65				255,613		48
Steve R. Secrist	45	213,891		55		Steve R. Secrist	65				222,607		48
Marla D. Mellies	45	148,804		48		Marla D. Mellies	65				226,493		58
Philip K. Bussey	45	140,688		46

_____________

* Target incentive of 90% of base salary, prorated and payable based on 4 months of service in 2019; actual % of base shown as annual value.

Long-Term Incentive Compensation

Long-term incentive compensation opportunities are designed to bealign the interests of executives with those of our investors, provide competitive ~~with market practices,~~pay opportunities, support a customer-focused utility, reward long-term performance and promote retention. Long-term incentive plan (LTI Plan) awards are denominated in units and are settled in cash if at least threshold performance measures are met. Performance measures ~~are~~have typically been based on two financial goals, ~~total return (Total Return)~~each weighted equally and ~~ROE, each~~ measured over a three-year performance ~~cycle.~~ cycle:

•Total return (Total Return) and

•ROE

The 2019-2021 grant cycle was focused exclusively on the ROE metric, as described below. Total Return reflects the change in the value of the Company during the performance cycle plus any distributions made to investors. ROE reflects the income earned on our equity investment. Achievement of each performance measure during the performance cycle is evaluated independently of the other.

The Committee recommends for Board approval a targeted LTI grant value for each executive, which is expressed as a percentage of base salary. The recommended and targeted LTI grant value is determined by evaluating LTI grant values provided to similarly situated executives at comparable companies (using the previously discussed survey and peer group data) as well as other relevant executive-specific factors. The Company generally does not consider previously granted awards or the level of accrued value from prior or other programs when making new LTI Plan grants.

The target LTI grant value is then converted into a target number of units, allocated equally among the two financial goals, based on the unit value on the grant date. The initial per-unit value is measured at the Puget Holdings level and is calculated annually by an independent auditing ~~firm.~~firm or based on market transactions. The number of units ultimately earned may range from 0% to 200% of target depending on performance, with the payout being made in cash based on the number of units earned and the per-unit value at the end of the performance period. Executives generally must be employed on the payment date to receive a cash payment under the LTI Plan, except in the event of retirement, disability or death.

The Committee recommends for Board approval the number of LTI Plan units granted to each executive by evaluating long-term incentive grant values provided to similarly situated executives at comparable companies (using the previously discussed survey and peer group data) as well as other relevant executive-specific factors. The Committee generally does not consider previously granted awards or the level of accrued value from prior or other programs when making new LTI Plan grants.

Half of the target units are earned based on Total Return and the other half are earned based on ROE, each over a 3-year performance period. These metrics and weightings have remained unchanged since the 2012 - 2014 grant cycle.

~~2016-2018~~2019-2021 Long-Term Incentive Plan Target Awards ~~and Performance Goals~~

Consistent with prior years, target LTI Plan awards for the ~~2016-2018~~2019-2021 performance cycle were calculated based on a percentage of an executive's annual base salary, taking into account the executive's level of responsibility within the Company and the corresponding market data. For Ms. Kipp, a target LTI Plan level of 220% of base salary for the 2019-2021 performance cycle was approved by the Board to provide immediate alignment with PSE and other executives. Target LTI Plan award amounts for the ~~2016-2018~~2019-2021 performance cycle ~~were 220% of base salary for Ms. Harris and 95% for Mr. Doyle, Mr. Secrist, Ms. Mellies and Mr. Bussey, which~~are shown in the following table.


Name						Target Long Term Incentive (% of Base Salary)
Kimberly J. Harris						265%
Mary E. Kipp						220
Daniel A. Doyle						95
Steve R. Secrist						95
Marla D. Mellies						95

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These percentages were unchanged from amounts established for the ~~2015-2017~~2018-2020 performance cycle, ~~except for~~with the exception of Ms. ~~Harris. The Board approved an increase~~Kipp who joined the Company in ~~Ms. Harris’ target award from 200% to 220% to provide a target level of award that was market competitive.~~2019. The total number of target LTI Plan units granted to a Named Executive Officer for the ~~2016-2018~~2019-2021 performance cycle is equal to the applicable percentage of salary

~~(converted~~ (converted to dollars) divided by the per unit value at the beginning of the performance cycle, including for Ms. Kipp, which was ~~$48.05.~~$81.86. Details of the number of units granted and expected values at target, threshold and maximum performance levels can be found in the ~~“2016~~“2019 Grants of Plan-Based Awards” table below. ~~Effective with the 2015-2017~~Prior outstanding LTI Plan grants, the Board approved a change in the calculation of performance results. Under this change, actual performance is measured as a percentage of target performance and plan funding is based on the modified payout scales shown below. Target Total Return is set annually by the Board prior to the grant date, and was set at 9.7% for the 2016-2018 performance cycle. Target ROE remains based on the ROE target in the Board’s approved budget for each year. Prior outstanding LTIP grants continue to have the performance targets and payout scales in effect at the time of grant.

~~The table below shows~~In connection with Mr. Kipp’s appointment as President in 2019 and anticipated appointment as CEO in 2020, in July 2019, the ~~percentage~~Board, upon the recommendation of ~~LTI Plan~~the Committee, also approved Ms. Kipp’s participation in the 2017-2019 performance cycle at a target ~~awards under~~amount of 110% of 2019 base salary and in the ~~Total Return component~~2018-2020 performance cycle at a target amount of 165% of 2019 base salary. Ms. Kipp’s target amounts reflected her reduced participation in these performance cycles that ~~could be earned based on three-year~~began prior to her commencement of employment and are intended to incentivize performance ~~during the 2016-2018~~in such performance ~~cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:~~cycles following commencement of employment



~~Annualized Three-Year Total Return Compared to Target~~	~~Plan Funding for Total Return (% of Target Units)~~
~~117.5% of Target or More~~	~~200.0%~~
~~115% of Target~~	~~185.5~~
~~110% of Target~~	~~157.0~~
~~105% of Target~~	~~128.5~~
~~100% of Total Return Target~~	~~100.0~~
~~95% of Target~~	~~92.9~~
~~90% of Target~~	~~85.7~~
~~85% of Target~~	~~78.6~~
~~82.5% of Target~~	~~75.0~~
~~80% of Target~~	~~56.7~~
~~75% of Target~~	~~20.0~~
~~<75% of Target~~	—

The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year performance period. Payout percentages will be interpolated if performance falls between the values shown below:



~~ROE Compared to Target~~	~~Plan Funding~~
~~117.5% of Target or More~~	~~200.0%~~
~~115% of Target~~	~~185.5~~
~~110% of Target~~	~~157.0~~
~~105% of Target~~	~~128.5~~
~~Target ROE~~	~~100.0~~
~~95% of Target~~	~~84.0~~
~~90% of Target~~	~~68.0~~
~~85% of Target~~	~~52.0~~
~~80% of Target~~	~~36.0~~
~~75% of Target~~	~~20.0~~
~~<75% of Target~~	—

~~Performance Scales for the 2015-2017 LTI Plan Grant~~

The table below shows the percentage of LTI Plan target awards under the Total Return component that could be earned based on three-year performance during the 2015-2017 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:



~~Annualized Three-Year Total Return Compared to Target~~	~~Plan Funding for Total Return (% of Target Units)~~
~~117.5% of Target or More~~	~~200.0%~~
~~115% of Target~~	~~185.5~~
~~110% of Target~~	~~157.0~~
~~105% of Target~~	~~128.5~~
~~100% of Total Return Target~~	~~100.0~~
~~95% of Target~~	~~89.6~~
~~90% of Target~~	~~79.2~~
~~88% of Target~~	~~75.0~~
~~85% of Target~~	~~62.3~~
~~80% of Target~~	~~41.2~~
~~75% of Target~~	~~20.0~~
~~<75% of Target~~	—



~~ROE Compared to Target~~	~~Plan Funding~~
~~117.5% of Target or More~~	~~200.0%~~
~~115% of Target~~	~~185.5~~
~~110% of Target~~	~~157.0~~
~~105% of Target~~	~~128.5~~
~~Target ROE~~	~~100.0~~
~~95% of Target~~	~~84.0~~
~~90% of Target~~	~~68.0~~
~~85% of Target~~	~~52.0~~
~~80% of Target~~	~~36.0~~
~~75% of Target~~	~~20.0~~
~~<75% of Target~~	—

~~Performance Scales for the 2014-2016 LTI Plan Grant~~

The table below shows the percentage of LTI Plan target awards under the Total Return component that could be earned based on three-year performance during the 2014-2016 performance cycle. Payout percentages will be linearly interpolated if performance falls between the values shown below:

Annualized Three-Year Total Return Plan Funding for Total Return (% of Target Units)
15% or more 200.0%
14% 180.0
13% 160.0
12% 140.0
11% 120.0
10% 100.0
9% 80.0
8% 60.0
7% 40.0
6% 20.0
<6% —

The table below shows the percentage of LTI Plan target awards under the ROE component that could be earned based on average performance during the three-year 2014-2016 performance period. Payout percentages will be interpolated if performance falls between the values shown below:



~~ROE Compared to Target~~	~~Plan Funding for ROE (% of Target Units)~~
~~Target + 250 bps~~	~~200.0%~~
~~Target + 200 bps~~	~~180.0~~
~~Target + 150 bps~~	~~160.0~~
~~Target + 100 bps~~	~~140.0~~
~~Target + 50 bps~~	~~120.0~~
~~Target ROE~~	~~100.0~~
~~Target - 50 bps~~	~~80.0~~
~~Target - 100 bps~~	~~60.0~~
~~Target - 150 bps~~	~~40.0~~
~~Target - 200 bps~~	~~20.0~~
~~<Target - 200 bps~~	—

Long-Term Incentive Plan Performance ~~2014-2016~~2017-2019 Performance Cycle Results and Payouts

The ~~2014-2016~~2017-2019 performance cycle has now ended. Amounts payable as a result of award vesting are shown in the following table:

•Performance on Total Return in 2019 was -1.2%, which was significantly lower than Total Return growth in 2018.

•Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of ~~8.28%~~19.9%, ~~below~~above target and at the ~~target but above~~maximum of the ~~threshold needed for payment.~~funding scale. The Total Return Component funded at ~~65.6%~~200% of target units.

•Performance on the ROE component of the grant was an average of ~~target plus 23 basis points for funding~~110.7% of target. The ROE component funded at ~~109.2%~~160.7% of target units.

Name

Target Incentive

(% of Base Salary)¹

Total Return Component

Units Granted/Paid

ROE Component

Units Granted/Paid

2014-2016

Actual LTIP Paid²

Name

Target Incentive

(% of Base Salary)¹

Total Return Component

Units Granted/Paid

ROE Component

Units Granted/Paid

2017-2019

Actual LTIP Paid²

Kimberly J. Harris

170%

18,545.5/12,165.8

18,545.5/20,251.7

1,697,706

Kimberly J. Harris

200%

22,770.5/45,541

22,770.5/36,592.2

6,642,111

Mary E. Kipp

110

5,778.2/11,556.3

5,778.2/9,285.5

1,685,478

Daniel A. Doyle

95%

5,551/3,641.5

5,551/6,061.7

508,154

Daniel A. Doyle

4,638.5/9,277

4,638.5/7,454.1

1,353,042

Steve R. Secrist

95%

4,057.5/2,661.7

4,057.5/4,430.8

371,435

Steve R. Secrist

3,663.0/7,326

3,663.0/5,886.4

1,068,490

Marla D. Mellies

95%

3,335/2,187.8

3,335/3,641.8

305,295

Marla D. Mellies

2,884.5/5,769

2,884.5/4,635.4

841,403

Philip K. Bussey

95%

3,359.5/2,203.8

3,359.5/3,668.6

307,538

______________


¹	¹Target LTI Plan incentive is a percentage of 2017 base salary when the grants were made in 2017 with a ~~percentage of 2014 base salary when the grants were made in 2014.~~


²	~~2014-2016 actual LTI Plan amount payable is equal to the~~ unit price of $52.37, except that Ms. Kipp’s target is a percentage of 2019 base salary equal to 50% of target LTI % of 220% with a per unit price of $81.86. ²2017-2019 actual LTI Plan amount payable is equal to the unit price of $80.87 multiplied by earned ~~Total Return and ROE component units.~~

~~Long-Term Incentive Plan Performance for Outstanding Cycles~~

The table below summarizes the status of the two other outstanding performance cycles from the initial grant date to December 31, 2016, with the projected payout assuming this same performance for the full three-year cycle under the applicable payout scales for Total Return and ~~ROE:~~ROE component units.

Performance Cycle
Cycle
Progress
Total Return Performance
Payout
(% of Target)
ROE Performance
Payout
(% of Target)
Total Projected Payout (based on performance as of 12/31/2016)
2015- 2017 67% Complete 8.4% 67% 100% 99% 82.8%
2016 - 2018 33% Complete 8.7% 85% 101% 103% 94.3%

Retirement Plans ~~- SERP~~–– Executive Retirement Plans and Retirement Plan

The Company maintains ~~the SERP~~executive retirement plans to attract and retain executives by providing a benefit that is coordinated with the tax-qualified Retirement Plan for Employees of Puget Sound Energy, Inc. (Retirement Plan). Without the addition of the ~~SERP,~~executive retirement plans, these executives would receive lower percentages of replacement income during retirement than other employees. All the Named Executive Officers participate in executive retirement plans—Ms. Harris, Mr. Doyle, Mr. Secrist and Ms. Mellies in the ~~SERP.~~SERP and Ms. Kipp in the Officer Restoration Benefit, as part of the Deferred Compensation Plan for Key Employees. Additional information regarding the SERP, Officer Restoration Benefit and the Retirement Plan is shown in the ~~“2016~~“2019 Pension Benefits” table.

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Deferred Compensation Plan

The Named Executive Officers are eligible to participate in the Deferred Compensation Plan for Key Employees (Deferred Compensation Plan). The Deferred Compensation Plan provides eligible executives an opportunity to defer up to 100% of base salary, annual incentive bonuses and earned LTI Plan awards, plus receive additional Company contributions made by PSE into an account that has three investment tracking fund choices. The funds mirror performance in major asset classes of bonds, stocks, and an interest crediting fund that changes rates quarterly. The Deferred Compensation Plan is intended to allow the executives to defer current income, without being limited by the Internal Revenue Code contribution limitations for 401(k) plans and therefore have a deferral opportunity similar to other employees as a percentage of eligible compensation. The Company contributions are also intended to restore benefits not available to executives under PSE’s tax-qualified plans due to Internal Revenue Code limitations on compensation and benefits applicable to those plans. Additional information regarding the Deferred Compensation Plan is shown in the ~~“2016~~“2019 Nonqualified Deferred Compensation” table.

Post-Termination Benefits

Effective March 30, 2009, the Company entered into Executive Employment Agreements with the Named Executive Officers ~~except Mr. Doyle (who was not then employed by~~at the ~~Company)~~time, including Ms. Harris and ~~Mr. Secrist (who was not then an officer).~~Ms. Mellies. The Executive Employment Agreements provide for an employment period of two years following a change in control and provide severance benefits in the event of a qualifying termination of employment within two years of a change in control. Since 2009, the Company has ceased entering into these agreements with new executive ~~officers. Mr. Bussey was an officer of PSE at March 30, 2009, but left PSE~~officers and, during 2019 only the agreements for Ms. Harris and Ms. Mellies remained in ~~May 2009 and upon his rehire in March 2012 does not have an employment~~effect. The agreement with ~~the Company.~~Ms. Harris terminated upon her retirement on January 2, 2020.

The Committee periodically reviews existing change in control and severance arrangements for the peer group companies. Based on this information, the Committee believes that the current arrangements generally provide benefits that are similar to those of the comparator group for longer tenured executives, but is not extending them to newly hired executives.

The “Potential Payments Upon Termination or Change in Control” section describes the current post-termination arrangements with the Named Executive Officers as well as other plans and arrangements that would provide benefits on termination of employment or a change in control, and the estimated potential incremental payments upon a termination of employment or change in control based on an assumed termination or change in control date of December 31, ~~2016.~~2019.

Other Compensation

~~In addition to base salary and annual and long-term incentive award opportunities, the~~The Company also provides the Named Executive Officers with benefits and limited perquisites. The Company may provide payments upon hiring a new executive to help offset the executive’s relocation expenses, a practice needed to attract qualified candidates from other areas of the country. In connection with Ms. Kipp’s commencement of employment, she received a hiring bonus in the amount of $800,000. Ms. Kipp is required to reimburse the Company for this bonus if she resigns or terminates for cause (as defined in her employment offer letter) within twelve months of payment. Ms. Kipp is also eligible to receive an additional bonus of $1,500,000 in the event the previously announced acquisition of El Paso by the Infrastructure Investments Fund, an investment vehicle advised by J.P. Morgan Incentive Management Inc. is completed in 2020.

The current executives participate in the same group health and welfare plans as other employees. Company vice presidents and above, including the Named Executive Officers, are eligible for additional disability and life insurance benefits. The executives are also eligible to receive reimbursement for financial planning, tax preparation and legal services ~~and business club memberships~~ up to an annual limit. The reimbursement for financial planning, tax preparation and legal services is provided to allow executives to concentrate on their business responsibilities. Business club memberships are provided to allow access for business meetings and business events at club facilities and executives are required to reimburse the Company for personal use of club facilities. These perquisites generally do not make up a significant portion of executive compensation and did not exceed $10,000 in total for each Named Executive Officer in ~~2016.~~2019. Executives are taxed on the value of the perquisites received, with no corresponding gross-up by the Company.

Relationship among Compensation Elements

A number of compensation elements increase in absolute dollar value as a result of increases to other elements. Base salary increases translate into higher dollar value opportunities for both annual and long-term incentives, because each plan operates with a target award set as a percentage of base salary. Base salary increases also increase the level of retirement benefits, as do actual annual incentive plan payments. Some key compensation elements are excluded from consideration when determining other elements of pay. Retirement benefits exclude LTI Plan payments in the calculation of qualified retirement (pension and 401(k)) and SERP benefits.

Impact of Tax and Accounting Treatment of Compensation

The accounting treatment of compensation generally has not been a significant factor in determining the amounts of compensation for our executive officers. However, the Company considers the accounting impact of various program designs

146

to balance the potential cost to the Company with the benefit/value to the executive. As a result of changes in federal tax law effective in 2018, the Company is now subject to IRS section 162(m). Section 162(m) limits the tax deductibility of compensation paid to certain executive officers, including the Named Executive Officers, to $1 million per year. Notwithstanding the new tax law, the Company does not expect to make changes in its executive compensation program designs.

Risk Assessment

A portion of each executive’s total direct compensation is variable, at risk and tied to the Company’s financial and operational performance to motivate and reward executives for the achievement of Company goals. The Company’s variable pay program helps focus executives on interests important to the Company and its investors and customers and creates a record of their results. In structuring its incentive programs, the Company also strives to balance and moderate risk to the Company from such programs: individual award opportunities are defined and subject to limits, goal funding is based on collective company performance, annual incentive awards are balanced by long-term incentive awards that measure performance over three years, performance targets are based on management’s operating plan (which includes providing good customer service), and all incentive awards to individual executives are subject to discretionary review by management, the Committee and/or the Board. As a result, the Committee and the Board believe that the programs’ design do not have risks that are reasonably likely to have a material adverse effect on the Company and also provide appropriate incentive opportunities for executives to achieve Company goals that support the interests of our investors and customers.

Compensation and Leadership Development Committee Report

The Board delegates responsibility to the Compensation and Leadership Development Committee to establish and oversee the Company’s executive compensation program. Each member of the Committee served during all of ~~2016,~~2019, except as noted below.

The Committee members listed below have reviewed and discussed the “Compensation Discussion and Analysis” with the Company’s management. Based on this review and discussion, the Committee recommended to the Board, and the Board has approved, that the “Compensation Discussion and Analysis” be included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2016~~2019, for filing with the SEC.

Compensation and Leadership

Development Committee of

Puget Energy, Inc.

Puget Sound Energy, Inc.

Steven Zucchet, chair, joined Committee May 1, 2019

~~Christopher Trumpy, Chair~~Scott Armstrong

~~Christopher Leslie~~

~~Etienne Middleton (served beginning May 5, 2016)~~Barbara Gordon

Mary McWilliams

Christopher Trumpy

Martijn Verwoest, joined Committee May 1, 2019

147

Summary Compensation Table

The following information is provided for the year ended December 31, ~~2016~~2019, (and for prior years where applicable) with respect to the Named Executive Officers during ~~2016.~~2019. The positions listed below are at Puget Energy and PSE, except that Ms. Mellies ~~and Mr. Bussey are executives~~is an executive of PSE only. Positions listed are those held by the Named Executive Officers as of December 31, ~~2016.~~2019. Salary and incentive compensation includes amounts deferred at the executive’s election.


Name and Principal Position	Year	Salary		Bonus¹		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation²		Change in Pension Value and Nonqualified Deferred Compensation Earnings³		All Other Compensation⁴		Total		Name and Principal Position	Year	Salary		Bonus¹		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation²		Change in Pension Value and Nonqualified Deferred Compensation³		All Other Compensation⁴		Total
Kimberly J. Harris	2016	$	900,000	$	269,595	$	—	$	—	$	2,615,706	$	650,281	$	20,338	$	4,455,920	Kimberly J. Harris	2019	$	989,799	$	—	$	—	$	—	$	7,382,111	$	3,373,594	$	28,864	$	11,774,368
President and Chief	2015	900,000		—		—		—		2,245,875		157,077		25,032		3,327,984		President and Chief	2018	939,823		45,220		—				6,593,310		445,343		20,888		8,044,584
Executive Officer⁵	2014	897,763		—		—		—		2,271,584		2,333,346		27,128		5,529,821		Executive Officer⁵	2017	900,001		50,940		—				5,293,105		1,523,783		20,338		7,788,167
Mary E. Kipp, President⁶																		Mary E. Kipp, President⁶	2019	252,540		—		—				1,876,398		—		813,893		2,942,831
Daniel A. Doyle	2016	$	508,322	$	18,299					$	742,885	$	370,670	$	49,836	$	1,690,012	Daniel A. Doyle	2019	521,399		—		—				1,608,655		964,614		63,555		3,158,223
Senior Vice President	2015	493,488		—		—		—		609,770		360,012		51,487		1,514,757		Senior Vice President	2018	519,039		—		—				1,718,288		489,180		60,657		2,787,164
and Chief Financial Officer⁶	2014	479,115		—		—		—		637,579		336,575		47,822		1,501,091
Chief Financial Officer⁷																		Chief Financial Officer⁷	2017	511,396		—		—				1,406,575		483,109		56,801		2,457,881
Steve R. Secrist	2016	$	383,085	$	50,510	$	—	$	—	$	549,678	$	268,972	$	41,344	$	1,293,589	Steve R. Secrist	2019	459,165		—		—				1,291,097		786,634		53,517		2,590,413
Senior Vice President,	2015	360,721		—		—		—		297,862		95,399		23,861		777,843
General Counsel, Chief Ethics & Compliance Officer⁷	2014	349,529		7,485		—		—		310,104		621,610		21,225		1,309,953
Senior Vice President																		Senior Vice President	2018	436,600		—		—				1,335,367		273,059		46,850		2,091,876
General Counsel, Chief Ethics & Compliance Officer⁸																		General Counsel, Chief Ethics & Compliance Officer⁸	2017	400,690		—		—				1,024,487		576,802		46,033		2,048,012
Marla D. Mellies	2016	$	306,901	$	20,588	$	—	$	—	$	447,014	$	279,975	$	30,414	$	1,084,892	Marla D. Mellies	2019	382,671		37,749		—				1,030,148		866,607		44,728		2,361,903
Senior Vice President,	2015	297,651		—		—		—		387,201		143,686		30,941		859,479
Chief Administrative Officer⁸	2014	287,868		12,367		—		—		385,549		388,950		30,126		1,104,860
Philip K. Bussey	2016	$	304,668	$	12,186	$	—	$	—	$	448,226	$	305,837	$	25,503	$	1,096,420
Senior Vice President, Chief Customer Officer⁹	2015	296,367		—		—		—		378,286		408,937		23,792		1,107,382
Senior Vice President																		Senior Vice President	2018	351,428		33,415		—				1,065,467		378,398		38,778		1,867,486
Chief Administrative Officer⁹																		Chief Administrative Officer⁹	2017	316,128		—		—				838,219		478,905		34,531		1,667,783

_______________

For 2016, reflects additional incentive paid based on review of 2015 results for SQIs as described in the "Compensation Discussion and Analysis," section titled "2015 Annual Incentive Review During 2016" in the amount of: Ms. Harris, $85,995; Mr. Doyle, $18,299; Mr. Secrist, $14,862; Ms. Mellies, $13,503; Mr. Bussey, $12,186 and includes adjustments to reflect individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2016 Annual Incentive Plan Results" in the amount of: Ms. Harris, $183,600; Mr. Secrist, $35,648; Ms. Mellies, $7,085.

For 2016, reflects annual cash incentive compensation paid under the 2016 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2014-2016 performance cycle. Cash incentive amounts were paid in early 2017 or deferred at the executive's election. The 2016 Goals and Incentive Plan and the LTI Plan are described in further detail under “Compensation Discussion and Analysis,” including the individual amounts paid to each Named Executive Officer in early 2017.

Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. In 2016, updated interest rate assumptions have increased the actuarial value of the underlying retirement benefits relative to assumptions for 2015. Information regarding these pension plans is set forth in further detail under “2016 Pension Benefits.” The change in pension value amounts for 2016 are: Ms. Harris, $646,248; Mr. Doyle, $370,670; Mr. Secrist, $268,972, Ms. Mellies, $279,410; and Mr. Bussey, $305,837. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2016 are: Ms. Harris, $4,033; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $565; and Mr. Bussey, $0. See the “2016 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.


⁴	~~All Other Compensation for 2016 is shown in detail in the table below.~~


⁵	~~Ms. Harris was promoted to President and CEO from President on March 1, 2011.~~


⁶	~~Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.~~


⁷	~~Mr. Secrist has worked at PSE since May 1989.~~


⁸	~~Ms. Mellies has worked at PSE since October 2005.~~


⁹	~~Mr. Bussey rejoined PSE as Senior Vice President and Chief Customer Officer on March 19, 2012.~~

^1.For 2019, reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2019 Annual Incentive Plan Results" in the amount of: $37,749 for Ms. Mellies.

^2.For 2019, reflects annual cash incentive compensation paid under the 2019 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2017-2019 performance cycle. Cash incentive amounts were paid in early 2020 or deferred at the executive's election. The 2019 Goals and Incentive Plan and the LTI Plan are described in further detail under “Compensation Discussion and Analysis,” including the individual amounts paid to each Named Executive Officer in early 2020.

^3.Reflects the aggregate increase in the actuarial present value of the executive’s accumulated benefit under all pension plans during the year. The amounts are determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements and include amounts which the executive may not currently be entitled to receive because such amounts are not vested. In 2019, updated interest rates relative to those used for 2018 have generally resulted in larger increases in value than in prior years. Information regarding these pension plans is set forth in further detail under “2019 Pension Benefits.” The change in pension value amounts for 2019 are: Ms. Harris, $3,371,078; Ms. Kipp, $0; Mr. Doyle, $964,614; Mr. Secrist, $786,634, and Ms. Mellies, $866,255. Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market. These amounts for 2019 are: Ms. Harris, $2,516, Ms. Kipp, $0, Mr. Doyle, $0; Mr. Secrist, $0; and Ms. Mellies, $352. See the “2019 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.

^4.All Other Compensation for 2019 is shown in detail in the table below.

^5.Ms. Harris was promoted to President and CEO from President on March 1, 2011, became CEO effective August 31, 2019, and retired on January 3, 2020.

^6.Ms. Kipp joined PSE and Puget Energy as President on August 31, 2019, and became President and CEO on January 3, 2020, with the retirement of Ms. Harris.

^7.Mr. Doyle joined PSE and Puget Energy as Senior Vice President and Chief Financial Officer on November 28, 2011.

^8.Mr. Secrist has worked at PSE since May 1989.

^9.Ms. Mellies has worked at PSE since October 2005.

148

Detail of All Other Compensation


Name	Perquisites and Other Personal Benefits¹		Registrant Contributions to Defined Contribution and Deferred Compensation Plans²		Other³		Name	Perquisites and Other Personal Benefits¹					Registrant Contributions to Defined Contribution and Deferred Compensation Plans²			Other³
Kimberly J. Harris	$	—	$	14,650	$	5,688	Kimberly J. Harris		$	5,000	$	15,416		$	8,448
Mary E. Kipp							Mary E. Kipp		5,000		6,773			802,121
Daniel A. Doyle	2,500		41,563		5,773		Daniel A. Doyle		2,500		53,851			7,204
Steve R. Secrist	3,502		33,043		4,799		Steve R. Secrist		1,370		46,822			5,325
Marla D. Mellies	1,050		26,269		3,095		Marla D. Mellies		493		39,097			5,138
Philip K. Bussey	475		18,550		6,478

_______________


¹	Reimbursement for financial planning, tax planning, and/or legal planning, with the initial plan up to a maximum of $5,000, and then annual reimbursement up to a maximum of $5,000 for Ms. Harris and $2,500 for the other Named Executive Officers.

Includes Company contributions during 2016 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 401(k) contributions are as follows: Ms. Harris, $14,650; Mr. Doyle, $18,550; Mr. Secrist $16,344 ; Ms. Mellies, $18,550; and Mr. Bussey, $18,550 Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $23,013; Mr. Secrist, $16,699; Ms. Mellies, $7,719; and Mr. Bussey, $0.


³	~~Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance.~~

^1.Reimbursement for financial planning, tax planning, and/or legal planning, with the initial plan up to a maximum of $5,000, and then annual reimbursement up to a maximum of $5,000 for Ms. Harris and Ms. Kipp and $2,500 for the other Named Executive Officers.

~~2016~~^2.Includes Company contributions during 2019 to PSE’s Investment Plan (a tax qualified 401(k) plan) and the Deferred Compensation Plan. Company 401(k) contributions are as follows: Ms. Harris, $15,416; Ms. Kipp, $6,773; Mr. Doyle, $19,550; Mr. Secrist $19,550; and Ms. Mellies, $19,550. Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Ms. Kipp, $0; Mr. Doyle, $34,301; Mr. Secrist, $27,272; and Ms. Mellies, $19,547.

^3.Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance for all Named Executive Officers. For Ms. Kipp also includes a signing bonus of $800,000 as described in the Compensation Discussion and Analysis, “Other Compensation.”

2019 Grants of Plan-Based Awards

The following table presents information regarding ~~2016~~2019 grants of non-equity annual incentive awards and LTI Plan awards, including, as applicable, the range of potential payouts for the awards.


		Estimated Future Payouts under Non-Equity Incentive Plan Awards									Estimated Future Payouts under Non-Equity Incentive Plan Awards
Name	Grant Date	Number Of Units Granted	Threshold		Target		Maximum		Name	Grant Date	Number Of Units Granted			Threshold				Target				Maximum
Kimberly J. Harris									Kimberly J. Harris
Annual Incentive¹	1/1/2016		$	270,000	$	900,000	$	1,800,000	Annual Incentive¹	1/1/2019		$	300,000			$	1,000,000			$	2,000,000
LTI Plan 2016-2018²	2/26/2016	41,207	488,880		2,613,760		5.473,938
LTI Plan 2019-2021²									LTI Plan 2019-2021²	2/21/2019	32,372	640,189				3,200,943				6,401,887
Mary E. Kipp									Mary E. Kipp
Annual Incentive¹									Annual Incentive¹	8/31/2019		$	77,400			$	258,000			$	516,000
LTI Plan 2019-2021³									LTI Plan 2019-2021³		23,113	457,075				2,285,377				4,570,754
LTI Plan 2018-2020³									LTI Plan 2018-2020³		17,334	321,893				1,609,465				3,218,930
LTIP Plan 2017-2019³									LTIP Plan 2017-2019³		11,556	201,498				1,007,490				2,014,981
Daniel A. Doyle									Daniel A. Doyle
Annual Incentive¹	1/1/2016		$	69,038	$	230,128	$	460,256	Annual Incentive¹	1/1/2019		$	103,627			$	345,423			$	690,846
LTI Plan 2016-2018²	2/26/2016	10,111	119,957		641,341		1,343,145
LTI Plan 2019-2021²									LTI Plan 2019-2021²	2/21/2019	6,167	121,959				609,793				1,219,586
Steve R. Secrist									Steve R. Secrist
Annual Incentive¹	1/1/2016		$	52,424	$	174,748	$	349,495	Annual Incentive¹	1/1/2019				$	90,246			$	300,820			$	601,640
LTI Plan 2016-2018²	2/26/2016	7,678	91,092		487,016		1,019,946
LTI Plan 2019-2021²									LTI Plan 2019-2021²	2/21/2019	5,371	106,217				531,084				1,062,169
Marla D. Mellies									Marla D. Mellies
Annual Incentive¹	1/1/2016		$	41,682	$	138,940	$	277,880	Annual Incentive¹	1/1/2019				$	76,518			$	255,060			$	510,120
LTI Plan 2016-2018²	2/26/2016	6,104	72,418		387,177		810,855
Philip K. Bussey
Annual Incentive¹	1/1/2016		$	41,379	$	137,930	$	275,859
LTI Plan 2016-2018²	2/26/2016	6,060	71,896		384,386		805,010
LTI Plan 2019-2021²									LTI Plan 2019-2021²	2/21/2019	4,554	90,060				450,300				900,599

_______________

As described in the “Compensation Discussion and Analysis,” the 2016 Goals and Incentive Plan had dual funding triggers in 2016 of $1,125 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,126 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,250 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,688 million EBITDA or higher and SQI/Safety measure performance at 10/10.


²	As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2016-2018 performance cycle were equally allocated between a Total Return component and an ROE component. Payments are calculated based on Total Return at Puget Holdings during the three-year performance cycle, the average three-year performance of ROE and the unit value at the end of the performance cycle.

^1.As described in the “Compensation Discussion and Analysis,” the 2019 Goals and Incentive Plan had dual funding triggers in 2019 of $1,206.9 million EBITDA and SQI performance of 6/10. Payment would be $0 if either trigger is not met. The threshold estimate assumes $1,206.9 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,341 million EBITDA and SQI/Safety measure performance at 10/10. The maximum estimate assumes $1,810.4 million EBITDA or higher and SQI/Safety measure performance at 10/10.

^2.As described in the “Compensation Discussion and Analysis,” LTI Plan grants for the 2019-2021 performance cycle were allocated 100% to the ROE component. Payments are calculated based on the average three-year performance of ROE and a unit value at the end of the performance cycle equal to $98.88, representing an increase in Total Return of 6.5% per year.

^3.Upon her hire on August 31, 2019, Ms. Kipp received LTIP grants of the units shown for the 2019-2021, 2018-2020, and 2017-2019 LTIP cycles.

~~2016~~

149

2019 Pension Benefits

The Company and its affiliates maintain two pension plans: the Retirement Plan and the ~~SERP.~~SERP, in addition to an Officer Restoration Benefit as part of the Deferred Compensation Plan. The following table provides information for each of the Named Executive Officers regarding the actuarial present value of the executive’s accumulated benefit and years of credited service under the Retirement Plan and the SERP. The present value of accumulated benefits was determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Each of the Named Executive Officers participates in both plans.


Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit ^1,2		Payments During Last Fiscal Year		Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit ^{1,2, 3}					Payments During Last Fiscal Year
Kimberly J. Harris	Retirement Plan	17.7	$	387,166	$	—	Kimberly J. Harris	Retirement Plan	20.7	$	588,937		$	—
								SERP	20.7	13,144,354		—
Mary E. Kipp							Mary E. Kipp	Retirement Plan	0.3	—		—
	SERP	17.7	8,011,240		—			Restoration Plan	0.3	—		—
Daniel A. Doyle	Retirement Plan	5.1	138,534		—		Daniel A. Doyle	Retirement Plan	8.1	269,865		—
	SERP	5.1	1,328,364		—			SERP	8.1	3,133,936		—
Steve R. Secrist	Retirement Plan	27.6	456,562		—		Steve R. Secrist	Retirement Plan	30.6	672,138		—
	SERP	27.6	2,214,826		—			SERP	30.6	3,635,745		—
Marla D. Mellies	Retirement Plan	11.2	276,461		—		Marla D. Mellies	Retirement Plan	14.2	436,224		—
	SERP	11.2	1,525,889		—			SERP	14.2	3,088,940		—
Philip K. Bussey	Retirement Plan	10.3	309,974		—
	SERP	10.3	1,638,506		—

_______________

^1.The amounts reported in this column for each executive were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination. The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2019, of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan and age 62 for the SERP). Future cash balance interest credits are assumed to be 4.0% annually. The discount assumption is 3.35%, and the post-retirement mortality assumption is based on the 2020 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.79%, 3.92%, and 4.38% (the 24-month average of the underlying rates as of September 2019), except that payments assumed to occur during 2020 use segment rates in effect for 2020 (this includes Ms. Harris' and Mr. Doyle's SERP present values). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2019. In order to determine the change in pension values for the Summary Compensation Table, the values of the Retirement Plan and the SERP benefits were also calculated as of December 31, 2018, for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2018. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.40% and post-retirement mortality assumption based on the 2019 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 2.28%, 3.81%, and 4.46% (the 24-month average of the underlying rates as of September 2018). Other assumptions used to determine the value as of December 31, 2018, were the same as those used for December 31, 2019.

^2.As described in footnote 1 above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumptions used for financial reporting purposes. These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts). The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer, except Ms. Harris, at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2019. Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2019.

^3.Ms. Kipp does not have a SERP benefit as that plan was closed prior to her joining PSE. Upon hire, Ms. Kipp elected to have her 4% company retirement contribution made to her 401(k) account. Ms. Kipp also participates in an Officer Restoration Benefit Plan as described below, with vesting after three years of service. Values of accumulated benefit will be shown after Ms. Kipp attains one year of service.

Name

The amounts reported in this column for each executive were calculated assuming no future service or pay increases. Present values were calculated assuming no pre-retirement mortality or termination. The values under the Retirement Plan and the SERP are the actuarial present values as of December 31, 2016 of the benefits earned as of that date and payable at normal retirement age (age 65 for the Retirement Plan and age 62 for the SERP). Future cash balance interest credits are assumed to be 4.0% annually. The discount assumption is 4.50%, and the post-retirement mortality assumption is based on the 2017 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.52%, 3.80%, and 4.79% (the 24-month average of the underlying rates as of September 2016). These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2016. In order to determine the change in pension values for the Summary Compensation Table, the values of the Retirement Plan and the SERP benefits were also calculated as of December 31, 2015 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2015. These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.65% and post-retirement mortality assumption based on the 2016 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.34%, 4.03% and 5.06% (the 24-month average of the underlying rates as of September 2015). Other assumptions used to determine the value as of December 31, 2015 were the same as those used for December 31, 2016.Estimated Lump Sum


Daniel A. Doyle	²	As described in footnote 1 above, the amounts reported for the SERP in this column are actuarial present values, calculated using the actuarial assumptions used for financial reporting purposes. These assumptions are different from those used to calculate the actual amount of benefit payments under the SERP (see text below for a discussion of the actuarial assumptions used to calculate actual payment amounts). The following table shows the estimated lump sum amount that would be paid under the SERP to each SERP-eligible Named Executive Officer at age 62 (without discounting to the present), calculated as if such Named Executive Officer had terminated employment on December 31, 2016. Each SERP-eligible Named Executive Officer (except Mr. Doyle) was vested in his or her SERP benefits as of December 31, 2016.	$	3,194,757
Steve R. Secrist			4,159,373
Marla D. Mellies			3,326,658

^{_______________________}

^4.As a result of retirement on January 2, 2020, Ms. Harris received a SERP lump sum in the amount of $13,144,354, calculated per the plan and paid according to Ms. Harris’ election of payment format.

150

Name Estimated Lump Sum
Kimberly J. Harris $ 12,081,432
Daniel A. Doyle 1,555,310
Steve R. Secrist 3,025,148
Marla D. Mellies 1,922,575
Philip K. Bussey 1,731,185

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 ~~2016,~~2019, the limit was ~~$265,000.~~$280,000. For ~~2017,~~2020, the limit is ~~$270,000.~~$285,000. 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 ~~2016~~2019 and ~~2017,~~2020, 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, ~~2016,~~2019, all the Named Executive Officers, except Ms. Kipp, 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. The Company closed the SERP plan to new participants as of August 1, 2019, but existing officer participants continue to accrue benefits in the plan. All the Named Executive Officers hired prior to 2019 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 are vested in their SERP benefits.

151

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 (i) below minus the sum of (ii) and (iii) below:

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.

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.

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 ~~“2016~~“2019 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.

Officer Restoration Benefit

The Officer Restoration Benefit provides a benefit to participating Officers that supplements the retirement income provided to the executives. Executives participating in the SERP are not eligible. Ms. Kipp participates in the benefit and those Company contributions under PSE’s applicable tax-qualified plan that would otherwise have been earned, if not for IRS limitations, are credited by the Company to an account within the Deferred Compensation Plan.

~~2016~~

152

2019 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 ~~2016~~2019 and year-end account balances under the Deferred Compensation Plan.


Name	Executive Contributions in 2016¹		Registrant Contributions in 2016²		Aggregate Earnings in 2016³		Aggregate Withdrawals/ Distributions		Aggregate Balance at December 31, 2016⁴		Name	Executive Contributions in 2019¹					Registrant Contributions in 2019²			Aggregate Earnings in 2019³					Aggregate Withdrawals/ Distributions	Aggregate Balance at December 31, 2019⁴
Kimberly J. Harris	$	—	$	—	$	12,114	$	—	$	312,189	Kimberly J. Harris		$	—	$	—		$	13,694		$	—	$	351,927
Mary E. Kipp											Mary E. Kipp		64,500		—			870			—		65,370
Daniel A. Doyle	250,495		23,013		42,035		—		798,771		Daniel A. Doyle		32,101		34,301			167,665			—		1,219,744
Steve R. Secrist	22,524		16,699		526		—		39,750		Steve R. Secrist		39,762		27,272			24,361			—		245,900
Marla D. Mellies	7,145		7,719		6,600		—		129,921		Marla D. Mellies		19,518		19,547			41,881			—		272,177
Philip K. Bussey	—		—		—		—		—

_______________

The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2016. Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $21,620; Mr. Secrist, $22,524; Ms. Mellies, $7,145; and Mr. Bussey, $0. Deferred incentive compensation amounts are: Ms. Harris, $0; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $0; and Mr. Bussey, $0. Mr. Doyle deferred $228,875 of LTIP earnings. The amounts are also included in the applicable column of the Summary Compensation Table for 2016.


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 2016.


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 2016.


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

^1.The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2019. Deferred salary amounts are: Ms. Harris, $0; Ms. Kipp, $64,500; Mr. Doyle, $32,101; Mr. Secrist, $39,762; and Ms. Mellies, $19,518. Deferred incentive compensation amounts are: Ms. Harris, $0; Ms. Kipp, $0; Mr. Doyle, $0; Mr. Secrist, $0; and Ms. Mellies, $0. The amounts are also included in the applicable column of the Summary Compensation Table for 2019.

Name Reported for 2016 Reported for 2015 Reported for 2014
Kimberly J. Harris $ 4,033
$ 3,259
$ 2,190
Daniel A. Doyle 273,509
259,782
132,127
Steve R. Secrist 39,223
—
—
Marla D. Mellies 15,428
17,869
16,314
Philip K. Bussey —
—
—
^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 2019.

^3.The amount in this column for each executive reflects the change in value of investment tracking funds. Amounts of zero indicate no change in value or a decrease in value. 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 2019.

^4.Of the amounts in this column, the amounts in the table below have also been reported in the Summary Compensation Table for 2019, 2018, and 2017.


Name	Reported for 2019					Reported for 2018			Reported for 2017
Kimberly J. Harris		$	2,516	$	2,154		$	3,165
Mary E. Kipp		—		—			—
Daniel A. Doyle		66,403		61,671			57,531
Steve R. Secrist		67,034		55,044			53,922
Marla D. Mellies		39,417		25,207			22,280

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 ~~2016~~2019 calendar year returns of these tracking funds were:



Vanguard Total Bond Market Index	~~2.61~~	%8.73%
Vanguard 500 Index	~~11.82~~	31.46
Vanguard Money Market Index	~~0.3~~	2.14
Interest Crediting Fund (pre-2012 deferrals)	~~4.10~~	4.12

153

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) a change in control; (ii) an involuntary termination without cause or for good reason in connection with a change in control; (iii) retirement; (iv) disability; or (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.

154

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 ~~2016,~~2019, 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.

155

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 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.

156

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, ~~2016.~~2019. 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	$	—	$	—	$	—	$	—	$	—	Kimberly J. Harris	$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	—		5,400,000		—		—		—		Cash Severance (salary and/or annual incentive)	—		6,000,000		—		—		—
Long Term Incentive Plan	4,072,922		4,072,922		—		3,543,948		3,543,948		Long Term Incentive Plan	12,000,606		12,000,606		—		12,000,606		12,000,606
SERP (additional years of credited service)¹	—		—		—		—		—		SERP (additional years of credited service)¹	—		—		—		—		—
Benefits (continuation)²	—		28,948		—		28,948		28,948		Benefits (continuation)²	—		30,700		—		30,700		30,700
Supplemental Life Insurance											Supplemental Life Insurance	—		—		—		—		3,400,000
Total Estimated Incremental Value											Total Estimated Incremental Value	$	12,000,606	$	18,031,306	$	—	$	12,031,306	$	15,431,306
Mary E. Kipp											Mary E. Kipp	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan											Long Term Incentive Plan	4,089,968		4,089,968		4,089,968		4,089,968		4,089,968
Benefits (continuation)¹											Benefits (continuation)¹	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		3,000,000		Supplemental Life Insurance	—		—		—		—		2,805,200
Total Estimated Incremental Value	$	4,072,922	$	9,501,870	$	—	$	3,572,896	$	6,572,896	Total Estimated Incremental Value	$	4,089,968	$	4,089,968	$	4,089,968	$	4,089,968	$	6,895,168
Daniel A. Doyle	$	—	$	—	$	—	$	—	$	—	Daniel A. Doyle	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	1,127,802		1,127,802		—		980,745		980,745		Long Term Incentive Plan	2,430,151		2,430,151		—		2,430,151		2,430,151
SERP (additional years of credited service)¹	—		—		—		—		—		SERP (additional years of credited service)¹	—		—		—		—		—
Benefits (continuation)²	—		—		—		—		—		Benefits (continuation)²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		971,652		Supplemental Life Insurance	—		—		—		—		1,222,266
Total Estimated Incremental Value	$	1,127,802	$	1,127,802	$	—	$	980,745	$	1,952,397	Total Estimated Incremental Value	$	2,430,151	$	2,430,151	$	—	$	2,430,151	$	3,652,417
Steve R. Secrist	$	—	$	—	$	—	$	—	$	—	Steve R. Secrist	$	—	$	—	$	—	$	—	$	—
Long Term Incentive Plan	829,360		829,360		—		721,581		721,581		Long Term Incentive Plan	1,908,392		1,908,392		—		1,908,392		1,908,392
SERP (additional years of credited service)¹	—		—		—		—		—		SERP (additional years of credited service)¹	—		—		—		—		—
Benefits (continuation)²	—		—		—		—		—		Benefits (continuation)²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		737,926		Supplemental Life Insurance	—		—		—		—		1,064,440
Total Estimated Incremental Value	$	829,360	$	829,360	$	—	$	721,581	$	1,459,507	Total Estimated Incremental Value	$	1,908,392	$	1,908,392	$	—	$	1,908,392	$	2,972,832
Marla D. Mellies	$	—	$	—	$	—	$	—	$	—	Marla D. Mellies	$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)	—		1,343,089		—		—		—		Cash Severance (salary and/or annual incentive)	—		1,942,380		—		—		—
Long Term Incentive Plan	679,185		679,185		—		590,616		590,616		Long Term Incentive Plan	1,563,151		1,563,151		—		1,563,151		1,563,151
SERP (additional years of credited service)¹	—		412,166		—		—		—		SERP (additional years of credited service)¹	—		430,688		—		—		—
Benefits (continuation)²	—		40,549		—		40,549		40,549		Benefits (continuation)²	—		48,853		—		48,853		48,853
Supplemental Life Insurance	—		—		—		—		586,636		Supplemental Life Insurance	—		—		—		0		902,520
Total Estimated Incremental Value	$	679,185	$	2,474,989	$	—	$	631,165	$	1,217,801	Total Estimated Incremental Value	$	1,563,151	$	3,985,072	$	—	$	1,612,004	$	2,514,524
Philip K. Bussey	$	—	$	—	$	—	$	—	$	—
Cash Severance (salary and/or annual incentive)
Long Term Incentive Plan	—		—		—		—		—
SERP (additional years of credited service)¹	679,377		679,377		—		590,805		590,805
Benefits (continuation)²	—		—		—		—		—
Supplemental Life Insurance	—		—		—		—		582,369
Total Estimated Incremental Value	$	679,377	$	679,377	$	—	$	590,805	$	1,173,174

_______________


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, 2016. 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.

^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, 2019. 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.

^3.Ms. Harris retired January 2, 2020, and per the LTIP plan is eligible for pro rata payments of LTIP grants for the 2018-2020 cycle of $3,871,077 and the 2019-2021 cycle of $1,105,636 to be paid in March 2020.

157

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 2019, our last completed fiscal year:

•The annual total compensation of our CEO, as reported in the 2019 Summary Compensation Table, was $11,774,369.

•The median of the annual total compensation of all our employees (excluding our CEO) was $125,510.

As a result, for 2019 the ratio of annual total compensation of our Chief Executive Officer to the median of our annual total compensation of all employees was 94:1. CEO total compensation was higher in 2019 than previous years due to the valuation of the CEO’s SERP benefit.Without SERP valuation impact, the CEO pay ratio would have been similar to 2018’s ratio of 65:1.

We identified our median employee by examining the total cash compensation we paid during 2019 to all individuals, excluding our CEO, who were employed by us on December 31, 2019, which totaled approximately 3,148 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 2019, we calculated annual total compensation for such employee for 2019 using the same methodology we use for our named executive officers as set forth in the 2019 Summary Compensation Table in accordance with the requirements of Item 402 (c)(2)(x) of Regulation S-K. Annual total compensation for 2019 for our median employee included annual salary, annual incentives, and company contributions towards benefits including retirement. Annual total compensation for 2019 for our CEO consists of the amount reported in the "Total" column of our 2019 Summary Compensation Table.

Director Compensation for Fiscal Year ~~2016~~2019

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 ~~2016~~2019 for service as directors. We refer to these directors as ~~nonemployee~~non-employee 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, Alan James, Christopher Leslie,~~Kenton Bradbury, Richard Dinneny, Chris Hind, Martijn Verwoest, and ~~Etienne Middleton. Kimberly Harris is employed by the Company and also serves as a director.~~Steven Zucchet.

As described in further detail below, the Company’s ~~nonemployee~~non-employee director compensation program in ~~2016~~2019 consisted of quarterly retainer cash fees of ~~$27,500.~~$35,000. 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		Name	Fees Earned		Nonqualified Deferred Compensation Earnings¹		Total
Scott Armstrong	$	136,000	$	—	$	136,000	Scott Armstrong	$	192,500	$	—	$	192,500
Melanie Dressel	186,600		—		186,600
Barbara Gordon							Barbara Gordon	170,000		—		170,000
Steve Hooper	—		140,400		140,400		Steve Hooper	—		231,400		231,400
David MacMillan	154,400		—		154,400
Thomas King							Thomas King	87,000		—		87,000
Paul McMillan	136,400		—		136,400		Paul McMillan	185,000		—		185,000
Mary O. McWilliams	131,600		—		131,600		Mary O. McWilliams	170,000		—		170,000
Herbert Simon²	12,367		—		12,367
Christopher Trumpy	140,400		—		140,400		Christopher Trumpy	185,800		—		185,800

_______________


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


²	~~Herbert Simon resigned from his position as a member of the Board of Directors of PSE, effective as of January 21, 2016.~~

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

~~Nonemployee~~

158

Non-employee Director Compensation Program

The ~~2016 nonemployee~~2019 non-employee director compensation program is based on the principles that the level of ~~nonemployee~~non-employee director compensation should be based on Board and committee responsibilities and should be competitive with comparable companies.

The ~~2016~~2019 compensation program for ~~nonemployee~~non-employee directors was as follows:

1.A base cash quarterly retainer fee of ~~$27,500;~~$35,000;

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

$2.A $1,600 per meeting fee ($800 for ~~each telephonic meeting lasting 60 minutes~~telephonic) will be paid when the number of Board or ~~less, and $1,600 for each telephonic meeting lasting more than 60 minutes.~~Committee meetings exceed six per year (not applicable to Asset Management Committee calls).

In ~~2016, nonemployee~~2019, non-employee directors were paid the following additional cash quarterly retainer fees:

1.Independent Board Chairman, $13,750;

2.Chair of the Compensation and Leadership Development Committee, ~~$2,000;~~$3,750;

3.Chair of the Governance ~~and Public Affairs Committees, $1,500;~~Committee, $3,750;

4.Chair of the Business Planning Committee, $3,750

5.Chair of the Audit Committee, ~~$2,500;~~$3,750; and

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

7.Additional retainer for ad hoc working group facilitator, $3,750

~~Nonemployee~~8.Additional payment (payable in cash in 2019; equity-like phantom stock or similar payments subsequent to 2019), $7,500

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

~~Nonemployee~~ Non-employee 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.

Deferral of Compensation

~~Nonemployee~~Non-employee 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~~non-employee directors. Non-employee 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~~Non-employee directors are permitted to make changes in measurement fund allocations quarterly. Steve Hooper is the only independent board member to defer any director fees during ~~2016.~~2019.

159

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, ~~2016~~2019, 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 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, ~~2016.~~2019.

Beneficial Ownership Table of Puget Energy and PSE

Number of Beneficially

Owned Shares

~~Name~~

~~Puget Energy~~

~~PSE~~

Name

Puget Energy

Puget Sound Energy

Puget Equico LLC and affiliates

200^{1, 2}

—

Puget Energy

—

85,903,791³

_______________

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 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:

¹Information 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), 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 (BCI), PIP2PX (Pad) Ltd. (PIP2PX) and PIP2GV (Pad) Ltd. (PIP2GV and together with MIP, PMGH, CPPIB, BCI 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. As of February 21, 2020:

•The address of the principal office of Puget Holdings, Puget Intermediate and Puget Equico is the PSE Building, ~~10885~~355 110th Ave 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~~BCI is ~~Suite 300-2950 Jutland Road,~~750 Pandora Ave, Victoria, British Columbia, Canada ~~V8T 5K2.~~V8W 0E4.

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

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.

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.

In August 2018, Macquarie Infrastructure Partners and Macquarie Capital Group Limited reached an agreement to sell their shares to Ontario Municipal Employee Retirement System (OMERS), PGGM Vermogensbeheer B.V. and current owners, AIMCo and BCI. The sale was approved by various federal and state agencies, including that of the Washington Commission, and closed on April 17th, 2019.

•The address of the principal office of OMERS is 900-100 Adelaide Street West, Toronto, Ontario, Canada, M5H E02

•The address of the principal office of PGGM Vermogensbeheer B.V. is Noordweg Noord 150, 3704 JG Zeist, Netherlands

²Pursuant 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.

³Pursuant 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.

160

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:

1.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.

2.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.

3.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:

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

2.Whether the terms are comparable to those generally available in arm's length transactions; and

3.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 and as a result, PSE paid Group Health a total of $23.3 million and $20.3 million for medical coverage for the year ended December 31, 2016 and 2015, respectively.

Kimberly Harris, ~~the~~former President and Chief Executive Officer and a director of Puget Energy and PSE, who retired effective January 2, 2020, is married to Kyle Branum, who ~~through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum~~ is a partner at Summit Law Group, which provides legal services to PSE. ~~In 2016 and 2015, Riddell Williams~~Summit Law Group was paid ~~$1.0~~$0.7 million ~~and $1.8 million, respectively,~~ for legal services provided to PSE in 2019, and Mr. Branum was 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.

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 who: (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), (ii) shall not be an officer or employee of PSE, (iii) shall be a resident of the state of Washington, and (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.

161

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. Mr. Hooper, ~~and~~ Mr. Armstrong, and Ms. McWilliams ~~and Ms. 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, in isolation, 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 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, ~~2016~~2019, and ~~2015~~2018 were as follows:


	2016				2015					2019						2018
(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE		(Dollars in Thousands)	Puget Energy		PSE		Puget Energy		PSE
Audit fees¹	$	2,597	$	2,397	$	2,413	$	2,128	Audit fees¹	$	2,630	$	2,378	$	2,695	$	2,495
Audit related fees²	47		47		45		45		Audit related fees²	114		114		204		204
Tax fees³	—		—		—		—		Tax fees³	—		—		—		—
Other fees⁴	383		383		52		52		Other fees⁴	52		52		204		204
Total	$	3,027	$	2,827	$	2,510	$	2,225	Total	$	2,796	$	2,544	$	3,103	$	2,903

_______________


¹	For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements and reviews of financial statements included in the Company’s Forms 10-Q. The 2016 fees are estimated and include an aggregate amount of $1.4 million billed to Puget Energy and $1.2 million to PSE through December 2016.


²	~~Consists of work performed in connection with registration statements and other regulatory audits.~~


³	~~Consists of tax consulting and tax return reviews.~~


⁴	~~Consists of software and research tools.~~

^1.For professional services rendered for the audit of Puget Energy’s and PSE’s annual financial statements and reviews of financial statements included in the Company’s Forms 10-Q. The 2019 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2019.

^2.Consists of work performed in connection with registration statements and other regulatory audits.

^3.Consists of tax consulting and tax return reviews.

^4.Consists of software and research tools.

The Audit Committee of the Company has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent registered public accounting firm. The policies are designed to ensure that the provision of these services does not impair the firm’s independence. Under the policies, unless a type of service to be provided by the independent registered public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee.

162

The annual audit services engagement terms and fees, as well as any changes in terms, conditions and fees relating to the engagement, are subject to specific pre-approval by the Audit Committee. In addition, on an annual basis, the Audit Committee grants general pre-approval for specific categories of audit, audit-related, tax and other services, within specified fee levels, that may be provided by the independent registered public accounting firm. With respect to each proposed pre-approved service, the independent registered public accounting firm is required to provide detailed back-up documentation to the Audit Committee regarding the specific services to be provided. Under the policies, the Audit Committee may delegate pre-approval authority to one or more of their members. The member or members to whom such authority is delegated shall report any pre-approval decision to the Audit Committee at its next scheduled meeting. The Audit Committee does not delegate responsibilities to pre-approve services performed by the independent registered public accounting firm to management.

For ~~2016~~2019 and ~~2015,~~2018, all audit and non-audit services were pre-approved.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


a)	~~Documents filed as part of this report:~~

a)Documents filed as part of this report:

1) Financial Statements

2) Financial Statement Schedules. Financial Statement Schedules of the Company, as required for the years

ended December 31, ~~2016, 2015~~2019, 2018, and ~~2014,~~2017, consist of the following:

I. Condensed Financial Information of Puget Energy

II. Valuation of Qualifying Accounts and Reserves

3) Exhibits

ITEM 16. FORM 10-K SUMMARY

None.

~~SIGNATURES~~

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

163



~~PUGET ENERGY, INC.~~		~~PUGET SOUND ENERGY, INC.~~

~~/s/ Kimberly J. Harris~~		~~/s/ Kimberly J. Harris~~
~~Kimberly J. Harris~~		~~Kimberly J. Harris~~
~~President and Chief Executive Officer~~		~~President and Chief Executive Officer~~

~~Date:~~	~~March 2, 2017~~	~~Date:~~	~~March 2, 2017~~

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each registrant and in the capacities and on the dates indicated.



~~Signature~~	~~Title~~	~~Date~~
	~~(Puget Energy and PSE unless otherwise noted)~~

~~/s/ Kimberly J. Harris~~	~~President and~~	~~March 2, 2017~~
~~(Kimberly J. Harris)~~	~~Chief Executive Officer~~

~~/s/ Daniel A. Doyle~~	~~Senior Vice President and~~
~~(Daniel A. Doyle)~~	~~Chief Financial Officer~~

~~/s/ Matthew Marcelia~~	~~Controller and Principal Accounting Officer~~
~~(Matthew Marcelia)~~

~~/s/ Scott Armstrong~~	~~Director of PSE only~~
~~(Scott Armstrong)~~

~~/s/ Andrew Chapman~~	~~Director~~
~~(Andrew Chapman)~~

~~/s/ Steven W. Hooper~~	~~Director~~
~~(Steven W. Hooper)~~

~~/s/ Karl Kuchel~~	~~Director~~
~~(Karl Kuchel)~~

~~/s/ Christopher J. Leslie~~	~~Director~~
~~(Christopher J. Leslie)~~

~~/s/ David MacMillan~~	~~Director~~
~~(David MacMillan)~~



~~/s/ Paul McMillan~~	~~Director~~
~~(Paul McMillan)~~

~~/s/ Mary O. McWilliams~~	~~Director~~
~~(Mary O. McWilliams)~~

	~~Director~~
~~(Etienne Middleton)~~

~~/s/ Christopher Trumpy~~	~~Director~~
~~(Christopher Trumpy)~~

EXHIBIT INDEX

Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the SEC and are incorporated herein by reference.



	2.1	Agreement and Plan of Merger, dated October 25, 2007, by and among Puget Energy, Inc. Padua Holdings LLC, Padua Intermediate Holdings Inc. and Padua Merger Sub Inc. (incorporated herein by reference to Exhibit 2.1 to Puget Energy’s Current Report on Form 8-K, dated October 25, 2007, Commission File No. 1-16305).
	3(i).1	Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
	3(i).2	Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
	3(ii).1	Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
	3(ii).2	Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
***	4.1	Indenture between Puget Sound Energy, Inc. and U.S. Bank National Association (as successor to State Street Bank and Trust Company) defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-a to Puget Sound Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, Commission File No. 1-4393).
	4.2	First, Second, Third, Fourth, and ~~Fourth~~Fifth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s senior notes (incorporated herein by reference to Exhibit 4-b to Puget Sound Energy’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.26 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated November 2, 2000 (Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.), Commission File No. 1-4393; ~~and~~ Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, 2003, Commission File No. ~~1-4393).~~1-4393 and Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 23, 2018, Commission File No. 1-4393.)
	4.3	Fortieth through Sixtieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bond (incorporated herein by reference to ~~Exhibits 4.3 through and including 4.23 to~~ Puget Sound Energy’s Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960).
	~~4.4~~	Exhibits 4.3 through and including 4.23: 4.3, 4.4, 4.5, 4.6, 4.7, 4.8, 4.9. 4.10, 4.11, 4.12, 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19, 4.20, 4.21, 4.22, 4.23.
***	4.4	Sixty-first through Eighty-seventh Supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1985, (Exhibit originally filed with Securities and Exchange Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated April 22, 1986, Commission File No. 1-4393; Exhibit (4)(b) to Puget Sound Energy’s Current Report on Form 8-K, dated September 5, 1986, not available). Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393; Exhibits (4)-d and (4)-e to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4-c to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 20, ~~1998,~~1998.
		Commission File No. 1-4393; Exhibit 4.27 to Puget Sound Energy’s Current Report on Form 8-K, dated March 4, 1999.
		Commission File No. 1-4393; Exhibit 4.2 to Puget ~~Sound Energy’s~~Energy's Current Report on Form 8-K, dated November 2, ~~2000,~~ 2000.

164


		Commission File No. 1-4393; Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated May 28, ~~2003,~~ 2003.
		Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, ~~2004,~~ 2004.
		Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 23, ~~2005,~~ 2005.
		Commission File No. 1-4393; Exhibit 4.30 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, ~~2005,~~ 2005.
***		Commission File No. 1-4393); Exhibit 4.4 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, ~~2009,~~ 2009.
		Registration No. 333-132497-01; Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 13, 2006.
***		Commission File No. 1-4393; Exhibit 4.1 to Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, ~~2007,~~2007. Commission File No. 1-4393; and Exhibit 4.5 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, ~~2009,~~ 2009.
		Registration No. 333-132497-01); Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated September 8, 2009, Commission File No. 1-4393.
	~~4.5~~	Commission File No. 1-4393; Exhibit 4.28 to Puget Sound Energy's Current Report on 10-K for fiscal year ended December 31, 2004.
	4.5	Eighty-eighth, Eighty-ninth and Ninetieth Supplemental Indentures defining the rights of the holders of Puget Sound Energy's Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibits 4.1 through 4.3 to Puget Sound Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-4393).


		Exhibits 4.1 through 4.3: 4.1, 4.2, 4.3.
	4.6	Ninety-first and Ninety-second supplemental Indentures defining the rights of the holders of Puget Sound Energy’s Electric Utility First Mortgage Bonds (incorporated herein by reference to Exhibit 4.6 to Puget Sound Energy’s Registration Statement on Form S-3, filed January 24, ~~2014,~~2014. Registration No. 333-193555 and to Exhibit 4.4 to Puget Sound Energy’s Current Report on Form 8-K filed May 29, 2013).
	4.7	Indenture of First Mortgage, dated as of April 1, 1957, defining the rights of the holders of Puget Sound Energy’s Gas Utility First Mortgage Bonds (incorporated herein by reference to Puget Sound Energy’s Registration Statement on Form S-3ASR, filed March 13, 2009, Registration No. 333-157960).
	4.8	First, Sixth, Seventh, Sixteenth and Seventeenth Supplemental Indenture to the Gas Utility First Mortgage, dated as of April 1, 1957, August 1, 1966, February 1, 1967, June 1, 1977, and August 9, 1978, respectively (incorporated herein by reference to Exhibits 4.26 through and including 4.30 to Puget Sound Energy's Registration Statement on Form S-3, filed March 13, 2009, Registration No. 333-157960).
	~~4.9~~	Exhibits 4.26 through 4.30: 4.26, 4.27, 4.28, 4.29, 4.30.
***	4.9	Twenty-second Supplemental Indenture to the Gas Utility First Mortgage, dated as of July 15, 1986 (incorporated herein by reference to Exhibit 4-B.20 to Washington Natural Gas Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 1986, Commission File No. 0-951).
***	4.10	Twenty-seventh Supplemental Indenture to the Gas Utility First Mortgage, dated as of September 1, 1990 (incorporated herein by reference to Exhibit 4.12 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).
***	4.11	Twenty-eighth through Thirty-sixth Supplemental Indentures to the Gas Utility First Mortgage (incorporated herein by reference to Exhibit 4-A to Washington Natural Gas Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1993, Commission File No. 0-951; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-49599; Exhibit 4-A to Washington Natural Gas Company’s Registration Statement on Form S-3, Registration No. 33-61859; Exhibit 4.30 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2005,~~2005. Commission File No. 1-4393; Exhibits 4.22 and 4.23 to Puget Sound Energy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, Commission File No. 1-4393; and Exhibit 4.14 to Post-Effective Amendment No. 2 to Puget Sound Energy’s Registration Statement on Form S-3, filed February 9, 2009, Registration No. 333-132497-01).

165


			4.12			Unsecured Debt Indenture, dated as of May 18, 2001, between Puget Sound Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. (as successor to Bank One Trust Company, N.A.) defining the rights of the holders of Puget Sound Energy’s unsecured debentures (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy’s Current Report on Form 8-K, dated May 18, 2001, Commission File No. 1-4393).
			4.13			Second Supplemental Indenture to the Unsecured Debt Indenture, dated June 1, 2007, between Puget Sound Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. defining the rights of Puget Sound Energy’s Series A Enhanced Junior Subordinated Notes due June 1, 2067 (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393).
			4.14			Third Supplemental Indenture to the Unsecured Debt Indenture, dated March 19, 2018, between Puget Sound Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. defining the rights of Puget Sound Energy’s Series A Enhanced Junior Subordinated Notes due June 1, 2067 (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy’s Current Report on Form 8-K, dated March 26, 2018, Commission File No. 1-4393).
			4.15			Form of Replacement Capital Covenant of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy’s Current Report on Form 8-K, dated May 30, 2007, Commission File No. 1-4393).
			~~4.15~~ 4.16			Indenture and First Supplemental Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of December 6, 2010 (incorporated by reference to Exhibits 4.1 and 4.2 to Puget Energy's Current Report on Form 8-K, filed December 7, 2010, Commission File No. 1-16305).
			~~4.16~~ 4.17			Second Supplemental Indenture to the Indenture dated December 6, 2010 between Puget Energy, Inc. and Wells Fargo Bank, National Association defining the rights of Puget Energy’s Senior Secured Notes due September 1, 2021 (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, filed June 6, 2011, Commission File No. 1-16305).
			~~4.17~~ 4.18			Third Supplemental Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of June 15, 2012 (incorporated by reference to Exhibits 4.1 to Puget Energy's Current Report on Form 8-K, filed June 18, 2012, Commission File No. 1-16305).
			~~4.18~~ 4.19			Trust Indenture, dated as of May 1, 2013 (the “Indenture”), by and between the City and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
			~~4.19~~ 4.20			Loan Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and the City of Forsyth, Rosebud County, Montana. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
			~~4.20~~ 4.21			Pledge Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393).
			~~4.21~~ 4.22			Fourth Supplemental Indenture dated as of May 12, 2015, between Puget Energy, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Puget Energy’s Current Report on Form 8-K, dated May 13, 2015, Commission File No. 1-16305).


***			10.1
	~~10.1~~	First Amendment dated as of October 4, 1961 to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***			10.2	First Amendment dated February 9, 1965 to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***			10.3	Contract dated November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***			10.4	Power Sales Contract dated as of November 14, 1957 between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc., relating to the Rocky Reach Project (incorporated herein by reference to Exhibit 10.4 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).

166


***	10.5	Power Sales Contract dated May 21, 1956 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.5 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.6	First Amendment to Power Sales Contract dated as of August 5, 1958 between Puget Sound Energy, Inc. and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development (incorporated herein by reference to Exhibit 10.6 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.7	Power Sales Contract dated June 22, 1959 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.7 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.8	Agreement to Amend Power Sales Contracts dated July 30, 1963 between Public Utility District No. 2 of Grant County, Washington and Puget Sound Energy, Inc., relating to the Wanapum Development (incorporated herein by reference to Exhibit 10.8 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.9	Power Sales Contract executed as of September 18, 1963 between Public Utility District No. 1 of Douglas County, Washington and Puget Sound Energy, Inc., relating to the Wells Development (incorporated herein by reference to Exhibit 10.9 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.10	Construction and Ownership Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.10 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.11	Operation and Maintenance Agreement dated as of July 30, 1971 between The Montana Power Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 10.11 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.12	Contract dated June 19, 1974 between Puget Sound Energy, Inc. and P.U.D. No. 1 of Chelan County (incorporated herein by reference to Exhibit 10.12 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2009, Commission File No. 1-4393).
***	10.13	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Colstrip Project) (incorporated herein by reference to Exhibit (10)-55 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.14	Transmission Agreement dated April 17, 1981 between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project) (incorporated herein by reference to Exhibit (10)-56 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.15	Ownership and Operation Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and other Owners of the Colstrip Project (Colstrip 3 and 4) (incorporated herein by reference to Exhibit (10)-57 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.16	Colstrip Project Transmission Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of the Colstrip Project (incorporated herein by reference to Exhibit (10)-58 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***	10.17	Common Facilities Agreement dated as of May 6, 1981 between Puget Sound Energy, Inc. and Owners of Colstrip 1 and 2, and 3 and 4 (incorporated herein by reference to Exhibit (10)-59 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).


***			10.18
	~~10.18~~	Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and Puget Sound Energy, Inc. (Rocky Reach Project) (incorporated herein by reference to Exhibit (10)-66 to Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393).
***			10.19	Transmission Agreement dated as of December 30, 1987 between the Bonneville Power Administration and Puget Sound Energy, Inc. (Rock Island Project) (incorporated herein by reference to Exhibit (10)-74 to Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393).
***			10.20	Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990 among The Montana Power Company, The Washington Water Power Company (Avista), Portland General Electric Company, PacifiCorp and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-91 to Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393).
***			10.21	Amendment of Seasonal Exchange Agreement, dated December 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-107 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).
***			10.22	Capacity and Energy Exchange Agreement, dated as of October 4, 1991 between Pacific Gas and Electric Company and Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit (10)-108 to Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393).

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***			10.23	General Transmission Agreement dated as of December 1, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP93947) (incorporated herein by reference to Exhibit 10.115 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
***			10.24	PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and Puget Sound Energy, Inc. (BPA Contract No. DE-MS79-94BP94521) (incorporated herein by reference to Exhibit 10.116 to Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393).
			10.25	Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10-E.2 to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1995, Commission File No. 1-11271).
			10.26	Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (incorporated herein by reference to Exhibit 10-P to Washington Natural Gas Company’s Form 10-K for the fiscal year ended September 30, 1994, Commission File No. 1-11271).
			10.27	Product Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-1 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-4393).
			10.28	Reasonable Portion Power Sales Contract dated December 13, 2001 and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10-2 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
			10.29	Additional Products Sales Agreement dated December 13, 2001, and Amendment No. 1 thereto, between Public Utility District No. 2 of Grant County, Washington, and Puget Sound Energy, Inc., relating to the Priest Rapids Project (incorporated herein by reference to Exhibit 10.3 to Puget Sound Energy’s Report on Form 10-Q for the quarter ended June 30, 2002, Commission File No. 1-4393).
	~~10.30~~	Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on Form 8-K dated February 16, 2012, Commission File Nos. 1-16305 and 1-4393).
	~~10.31~~	Amendment No. 1 dated April 6, 2012 to Credit Agreement dated as of February 10, 2012 among Puget Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, the other agents party thereto, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Puget Energy's Report on Form 10-Q for the quarter ended March 31, 2012, Commission File No. 1-16305).
	~~10.32~~	Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administration Agent, the other agents party thereto, and the lenders party thereto. ~~(incorporated herein by reference to Exhibit 10.1 to Puget Energy’s and Puget Sound Energy’s Report on~~ ~~Form 8-K dated February 11, 2013, Commission File Nos. 1-16305 and 1-4393).~~
**			~~10.33~~ 10.30	Form of Executive Employment Agreement with ~~Executive~~E x ecutive Officers (incorporated herein by reference to Exhibit 10.1 to Puget Energy's and Puget Sound ~~Energy’s Current~~Energy's Curre nt Report on Form 8-K, dated April 3, 2009, Commission ~~File~~file Nos. 1-16305 and ~~1-4393)~~1-4393 ).


			10.31
**	~~10.34~~	Puget Sound Energy ~~Inc.~~In c. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2009 (incorporated herein by reference to Exhibit 10.39 to Puget ~~Energy’s~~Ene rgy 's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393 ).
			10.32	Puget Sound Energy , Inc. Amended and Res tated Supplemental Executive Retirement Plan e f fective Ja nuary 1, 2013. (incorporated here in by r eference 10.35 to Puget Ener gy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, 2012, Commission File Nos. 1-16305 and 1-4393 ).
**			10.33	Puget Sound E nergy, Inc. Amended and Resta ted Deferred Com pensation Plan for Key Employees effective Jan uary 1, 2009. (inco rpo rated herein by re ference to Exhibit 10.4 0 to Puget Ener gy's an d Pu get Sound Energy's Report on Form 10-K for the fiscal y ear end ed December 31, 20018, Commission File No. 1-6305 ).
**			10.34	Puget Sound Energy, Inc . Amended and Restated Def erred Compensatio n Plan for N onempl oyee D irectors effective Jan uary 1, 2009 (incorp orated herein by ref erence to Ex hibit 10.41 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal year ended December 31, ~~2008,~~200 8, Commission File No. 1-16305 and ~~1-4393).~~1-4393 )
**			10.35	~~Puget Sound Energy, Inc. Amended and Restated Supplemental Executive Retirement Plan effective January 1, 2013 (incorporated~~ Summary of D irector Compensation (inco rporated herein by ~~reference~~r eference to Exhibit ~~10.35~~10.38 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fisc al year ended December 31, 2015, Commission File No. 1-16305 and 1-4393.)
**			10.36	Puget So und Energy, Inc. Supplemental Death Benefit P lan for Executive Employees , effect ive October1, 2000, as amended (inco r porated he rein by refe rence to Exhibit 10.45 to Puget Energy's and Puget Sound Energy's Report on Form 10-K for the fiscal ~~year~~yea r ended December 31, ~~2012, Commission~~2008, Commis sion File ~~Nos.~~No. 1-16305 ~~and 1-4393)~~).
**			~~10.36~~ 10.37	Amend ment to Puget Sound Energy, ~~Inc. Amended and Restated Deferred Compensation~~In c. Supplementa l De ath Benefit Plan for ~~Key~~E xecutive Employees ,effective ~~January~~ Jan uary 1, ~~2009~~2002, as amended (incorporated herein by reference to ~~Exhibit 10.40~~Exh ibit 10.46 to Puget ~~Energy’s and Puget~~ Energy's an d Puge t Sound ~~Energy’s Report~~Energy's Re port on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and ~~1-4393)~~1-4393 ).

168


**			~~10.37~~ 10.38	Puget Sound Energy Inc. Amended and Restated Deferred Compensation Plan for Nonemployee Directors effective January 1, 2009 (incorporated herein by reference to Exhibit 10.41 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	~~10.38~~	~~Summary of Director Compensation (incorporated herein by reference to Exhibit 10.38 to Puget Energy’s and~~ ~~Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No.~~ ~~1-16305 and 1-4393).~~
**	~~10.39~~	~~Puget Sound Energy,~~, Inc. Supplemental ~~Death Benefit~~Di sability Plan for Executive Employees, effective October 1, 2000 as amended (incorporated herein by ~~reference~~refer ence to ~~Exhibit 10.45~~Exhibi t 10.47 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended ~~December~~Decembe r 31, ~~2008,~~200 8, Commission File No. 1-16305 and ~~1-4393)~~1-4393 ).
**			~~10.40~~ 10.39	Amendment to ~~Puget~~Pu get Sound Energy, Inc. Supplemental Death Benefit Plan for ~~Executive~~Execut ive Employees, effective ~~January~~Novem ber 1, ~~2002,~~2007, as ~~amended~~am ended (incorporated herein by ~~reference~~re ference to ~~Exhibit 10.46~~Exhibi t 10.48 to Puget ~~Energy’s~~Ener gy's and Puget Sound ~~Energy’s~~Energy's Report on Form 10-K for the fiscal year ended December 31 , 2008, Commission File No. 1-16305 and 1-4393).
**			~~10.41~~ 10.40	Puget Sound Energy, Inc. Supplemental Disability Plan for Executive Employees, effective October 1, 2000, as amended (incorporated herein by reference to Exhibit 10.47 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	~~10.42~~	Amendment to Puget Sound Energy, Inc. Supplemental Death Benefit Plan for Executive Employees, effective November 1, 2007, as amended (incorporated herein by reference to Exhibit 10.48 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-K for the fiscal year ended December 31, 2008, Commission File No. 1-16305 and 1-4393).
**	~~10.43~~	Puget Energy, Inc. Amended and Restated 2005 Long-Term Incentive Plan , effective ~~January~~Jan uary 21, 2016 (incorporated herein by reference to Exhibit 10.43 to Puget ~~Energy’s~~Energy's and Puget Sound ~~Energy’s~~Ener gy's Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File No. 1-16305 and 1-4393).
**			~~10.44~~ 10.41	~~Amendment No. 1 dated April 15, 2014 to~~ Credit Agreement dated as of February 4, 2013 among Puget Sound Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and the Lenders party thereto. (incorporated herein by reference to Exhibit 10.2 to Puget Energy’s and Puget Sound Energy’s Report on Form 10-Q for the quarter ended March 31, 2014, Commission File No. 1-16305 and 1-4393).
	~~10.45~~	~~Amendment No. 2 dated April 15, 2014 to Credit Agreement dated as of February 10, 2012~~October 25, 2017, among Puget Energy Inc., as Borrower, JPMorgan Chase Bank ~~National Association,~~N.A., as Administrative Agent, and the ~~Lenders~~lenders party thereto. (incorporated ~~herein~~ by reference to Exhibit 10.1 to Puget ~~Energy’s and Puget Sound Energy’s~~Energy's Current Report on Form ~~10-Q for~~8-K, filed October 31, 2017, Commission File No. 1-16305).
			10.42	Credit Agreement dated October 25, 2017, among Puget Sound Energy, Inc., as Borrower, Mizuho Bank, Ltd., as Administrative Agent, and the ~~quarter ended March~~lenders party thereto. (incorporated by reference to Exhibits 10.2 to Puget Sound Energy's Current Report on Form 8-K, filed October 31, ~~2014,~~2017, Commission ~~File~~file No. 1-4393).
**			10.43	Purchase Agreement, dated June 4, 2018, bet ween Puget Sound Energy, Inc. and J.P. Morgan Securities LL C, Merrill Lynch, Pier ce, Fenner & Sm ith Incorporated and Mizuho Secu rities USA LLC and each of the other underwriters named in Schedule A there to (inco rporated by reference herein to Exhibit 1.1 to Current Report on Form 8-K filed on June 5, 2018, Commission Fi le No. 1-4393).
			10.44	Term Loan Agreement, dated October 1, 2018, among Puget Ener gy, Toronto Dominion (Texas) LLC, as Administrat ive Agent, and the le nders party thereto (incorporated by reference herein to Exhibit 10.1 to Current Re port on Form 8-K file d on October 3, 2018, Commission file No. 1-16305 and 1-4393).
*			~~12.1~~ 21.1	~~Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2012 through 2016).~~
*	~~12.2~~	~~Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2012 through 2016).~~
*	~~21.1~~	Subsidiaries of Puget Energy, Inc.
*			21.2	Subsidiaries of Puget Sound Energy, Inc.
*			23.1	Consent of PricewaterhouseCoopers LLP
*			31.1	Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – ~~Kimberly J. Harris.~~Mary E. Kipp .
*			31.2	Certification of Puget Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.
*			31.3	Certification of Puget Sound Energy, Inc. - Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – ~~Kimberly J. Harris.~~Mary E. Kipp
*			31.4	Certification of Puget Sound Energy, Inc. – Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.
*			32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – ~~Kimberly J. Harris.~~

Mary E. Kipp.


*			32.2
*	~~32.2~~	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 – Daniel A. Doyle.
*			101	Financial statements from the Annual Report on Form 10-K of Puget Energy, Inc. and Puget Sound Energy, Inc. for the fiscal year ended December 31, ~~2016,~~2018, filed on ~~March 2, 2017,~~February 20, 2019, formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements (submitted electronically herewith).
*			101.INS	Inline XBRL Instance
*			101.SCH	Inline XBRL Taxonomy Extension Schema
*			101.CAL	Inline XBRL Taxonomy Extension Calculation
*			101.DEF	Inline XBRL Taxonomy Extension Definition
*			101.LAB	Inline XBRL Taxonomy Extension Label
*			101.PRE	Inline XBRL Taxonomy Extension Presentation
*			104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

_______________

169

*Filed herewith.

** Management contract, compensatory plan or arrangement.

*** Exhibit originally filed with the Securities and Exchange Commission in paper format and as such, a hyperlink is not available.

SIGNATURES

*PUGET ENERGY, INC.

~~Filed herewith.~~

PUGET SOUND ENERGY, INC.

/s/ Mary E. Kipp

Mary E. Kipp

President and Chief Executive Officer

Date:

February 21, 2020

Date:

February 21, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person son behalf of each registrant and in the capacities and on the dates indicated.

170


**Signature	~~Management contract, compensatory plan or arrangement.~~Title	Date
	(Puget Energy and PSE unless otherwise noted)

/s/ Mary E. Kipp	President and	February 21, 2020
(Mary E. Kipp)	Chief Executive Officer

/s/ Daniel A. Doyle	Senior Vice President and
(Daniel A. Doyle)	Chief Financial Officer

/s/ Stephen J. King	Controller and Principal Accounting Officer
(Stephen J. King)

/s/ Scott Armstrong	Director
(Scott Armstrong)

/s/ Kenton Bradbury	Director
(Kenton Bradbury)

/s/ Steven W. Hooper	Director
(Steven W. Hooper)

/s/ Tom King	Director
(Tom King)

/s/ Richard Dinneny	Director
(Richard Dinneny)

/s/ Barbara Gordon	Director of PSE Only
(Barbara Gordon)

/s/ Christopher Hind	Director
(Christopher Hind )


/s/ Paul McMillan			Director
(Paul McMillan)

/s/ Mary O. McWilliams			Director
(Mary O. McWilliams)

/s/ Christopher Trumpy			Director
(Christopher Trumpy)

/s/ Martijn Verwoest			Director
(Martijn Verwoest)

/s/ Steven Zucchet			Director
(Steven Zucchet)

~~166~~

171



Utility Plant Additions/Retirements 5-Year Total	2012-2016
(Dollars in Thousands)	Electric	Natural Gas	Common
Additions	$2,916,114	$758,141	$349,578
Retirements	(453,220)	(98,317)	(254,106)
Net Utility Plant	$2,462,894	$659,824	$95,472



Utility Plant Balance	December 31, 2016
(Dollars in Thousands)	Electric		Natural Gas		Common
Distribution	$3,587,449	36.5%	$3,329,151	91.4%	$—	—%
Generation	4,118,431	42.0	6,737	0.2	—	—
Transmission	1,420,334	14.5	—	—	—	—
General Plant & Other	686,955	7.0	304,383	8.4	632,718	100.0
Total	$9,813,169	100.0%	$3,640,271	100.0%	$632,718	100.0%



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



Electric Margin	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2016			2015						2014
Electric operating revenue:
Residential sales	$	1,138,871		$	1,061,117		$	77,754		$	1,003,205		$	57,912
Commercial sales	872,057			867,786			4,271			824,778			43,008
Industrial sales	113,469			114,223			(754		)	107,750			6,473
Other retail sales	20,045			20,216			(171		)	19,707			509
Total retail sales	2,144,442			2,063,342			81,100			1,955,440			107,902
Transportation sales	10,937			10,143			794			9,502			641
Sales to other utilities and marketers	50,124			46,666			3,458			41,680			4,986
Decoupling revenue	29,968			13,630			16,338			25,735			(12,105		)
Other decoupling revenue¹	(21,168		)	(16,634		)	(4,534		)	5,609			(22,243		)
Other	24,189			11,321			12,868			45,831			(34,510		)
Total electric operating revenues²	2,238,492			2,128,468			110,024			2,083,797			44,671
Minus power costs:
Purchased electricity²	(531,596		)	(499,522		)	(32,074		)	(514,087		)	14,565
Electric generation fuel²	(215,331		)	(249,907		)	34,576			(263,493		)	13,586
Residential exchange²	69,824			112,473			(42,649		)	129,036			(16,563		)
Total electric power costs	(677,103		)	(636,956		)	(40,147		)	(648,544		)	11,588
Electric margin³	$	1,561,389		$	1,491,512		$	69,877		$	1,435,253		$	56,259

Electric Energy Sales
MWh
Residential sales	10,245,326			10,164,703			80,623			10,349,928			(185,225		)
Commercial sales	8,895,950			8,999,068			(103,118		)	8,900,863			98,205
Industrial sales	1,223,214			1,257,958			(34,744		)	1,226,588			31,370
Other retail sales	90,753			94,847			(4,094		)	98,499			(3,652		)
Total energy sales to customers	20,455,243			20,516,576			(61,333		)	20,575,878			(59.302		)



Benefit/(Expense)	Year Ended December 31,						Dollar Change			Year Ended December 31,			Dollar Change
(Dollars in Thousands)	2016			2015						2014
PSE net income	$	380,581		$	304,189		$	76,392		$	236,614		$	67,575
Other operating revenue and income	(316		)	(558		)	242			(2,949		)	2,391
Net unrealized gain on derivative instruments	—			544			(544		)	1,491			(947		)
Non-utility expense and other	10,710			15,801			(5,091		)	10,620			5,181
Non-hedged interest rate swap expense	(1,062		)	(3,796		)	2,734			(3,915		)	119
Interest expense ¹	(112,156		)	(109,125		)	(3,031		)	(102,382		)	(6,743		)
Income tax benefit (expense)	35,142			34,124			1,018			32,356			1,768
Puget Energy net income	$	312,899		$	241,179		$	71,720		$	171,835		$	69,344



Equity Value Sensitivity Table
(Dollars in Billions)
Weighted-Average Cost of Capital Rate	Long-Term Growth Rate
	2.4		%	2.5		%	2.6		%	2.7		%	2.8		%	2.9		%
5.9%	$	3.5		$	3.8		$	4.1		$	4.5		$	4.8		$	5.2
5.7	4.4			4.8			5.2			5.6			6.0			6.4
5.4	5.5			5.9			6.4			6.8			7.3			7.9



Puget Energy
Interest Rate Swap Contracts Asset (Liability)
(Dollars in Thousands)
Fair value of contracts outstanding at December 31, 2015	$	(5,050	)
Contracts realized or otherwise settled during 2016	2,008
Change in fair value of derivatives	2,901
Fair value of contracts outstanding at December 31, 2016	$	(141	)



Effective Date	Reduction in Rate Increases due to Excess Earnings (Dollars in Millions)
Electric:
2016 (estimated)	$11.2
2015	16.3
2014	3.4
Natural Gas:
2016 (estimated)	$2.1
2015	9.2
2014	—



Effective Date Accrued Through	Deferrals not Included in Annual Rate Increases (Dollars in Millions)
Electric:
2015	$—
2014	1.9
Natural Gas:
2015	$28.7
2014	8.2



(Dollars in Thousands)
At December 31,
Years	Operating Lease Expense
2016	$	31,786
2015	27,843
2014	30,737



Puget Energy and Puget Sound Energy	At Year Ended December 31,
(Dollars in Thousands)	Volumes (millions)		Assets¹				Liabilities²
	2016	2015	2016		2015		2016		2015
Interest rate swap derivatives³	$450.0	$450.0	$	—	$	—	$	141	$	5,050
Electric portfolio derivatives	*	*	36,460		23,443		41,329		112,106
Natural gas derivatives (MMBtus)⁴	336.4	369.5	26,619		6,200		19,101		67,090
Total derivative contracts	**	**	$	63,079	$	29,643	$	60,571	$	184,246
Current	**	**	$	54,341	$	24,418	$	44,310	$	136,173
Long-term	**	**	8,738		5,225		16,261		48,073
Total derivative contracts	**	**	$	63,079	$	29,643	$	60,571	$	184,246



Puget Energy and Puget Sound Energy	Year Ended December 31,
Level 3 Roll-Forward Net (Liability)	2016									2015									2014
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)
Changes during period
Realized and unrealized energy derivatives:
Included in earnings¹	4,007			—			4,007			(6,432		)	—			(6,432		)	(5,537		)	—			(5,537		)
Included in regulatory assets / liabilities	—			4,312			4,312			—			3,695			3,695			—			1,630			1,630
Settlements²	(1,129		)	(2,679		)	(3,808		)	902			(3,885		)	(2,983		)	1,036			(1,534		)	(498		)
Transferred into Level 3	(3,021		)	—			(3,021		)	(787		)	—			(787		)	5,155			(585		)	4,570
Transferred out of Level 3	8,460			1,375			9,835			11,034			(153		)	10,881			2,705			(1,190		)	1,515
Balance at end of period	$	972		$	625		$	1,597		$	(7,345	)	$	(2,383	)	$	(9,728	)	$	(12,062	)	$	(2,040	)	$	(14,102	)



	Recurring Fair Value Measures							Recurring Fair Value Measures
	As of December 31, 2016							As of December 31, 2015
(Dollars in Thousands)	Level 1		Level 2		Total			Level 1		Level 2		Total
Assets:
Mutual Funds	$	181,212	$	—	$	181,212		$	169,165	$	—	$	169,165
Common Stock	154,255		—		$	154,255		146,321		—		$	146,321
Government Securities	18,754		16,197		$	34,951		8,835		14,268		$	23,103
Corporate Bonds	—		38,543		$	38,543		—		44,157		$	44,157
Subtotal	354,221		54,740		408,961			324,321		58,425		382,746
Investments measured at NAV¹	*		*		222,819			*		*		223,663
Net (payable) receivable	*		*		(9,894		)	*		*		(7,544		)
Total assets	*		*		$	621,886		*		*		$	598,865



Puget Energy	2016 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third		Fourth
Operating revenue	$	962,697	$	668,169	$	618,278	$	915,157
Operating income	284,824		175,634		88,072		236,854
Net income (loss)	141,186		64,553		2,335		104,825



	2015 Quarter
(Unaudited; Dollars in Thousands)	First		Second		Third			Fourth
Operating revenue	$	926,835	$	658,341	$	605,733		$	901,791
Operating income	245,235		126,772		69,888			230,030
Net income (loss)	115,676		25,616		(7,928		)	107,815



Custom Survey Peer Group
1.	AGL Resources	10.	MDU Resources Group	19.	Teco Energy
2.	Alliant Energy	11.	NiSource	20.	UIL Holdings
3.	Ameren	12.	OGE Energy	21.	UNS Energy
4.	Atmos Energy	13.	Oncor Electric Delivery	22.	Vectren
5.	Avista	14.	Pinnacle West Capital	23.	Westar Energy
6.	Black Hills	15.	PNM Resources	24.	Wisconsin Energy
7.	CMS Energy	16.	Portland General Electric
8.	CPS Energy	17.	SCANA
9.	LLG&E and KU Energy	18.	Southwest Gas



Annual Incentive Performance Payout Scale and Actual Performance
Performance	2016 EBITDA (In Millions)		SQI & Safety*	Funding Level
Maximum	$	1,688.0	10/10	200	%
Target	1,250.0		10/10	100
Threshold	1,125.0		6/10	30
2016 Actual Performance	$	1,255.3	10/10	102	%



Annualized Three-Year Total Return	Plan Funding for Total Return (% of Target Units)
15% or more	200.0%
14%	180.0
13%	160.0
12%	140.0
11%	120.0
10%	100.0
9%	80.0
8%	60.0
7%	40.0
6%	20.0
<6%	—



Performance Cycle	Cycle Progress	Total Return Performance	Payout (% of Target)	ROE Performance	Payout (% of Target)	Total Projected Payout (based on performance as of 12/31/2016)
2015- 2017	67% Complete	8.4%	67%	100%	99%	82.8%
2016 - 2018	33% Complete	8.7%	85%	101%	103%	94.3%



Name	Estimated Lump Sum
Kimberly J. Harris	$	12,081,432
Daniel A. Doyle	1,555,310
Steve R. Secrist	3,025,148
Marla D. Mellies	1,922,575
Philip K. Bussey	1,731,185



Name	Reported for 2016		Reported for 2015		Reported for 2014
Kimberly J. Harris	$	4,033	$	3,259	$	2,190
Daniel A. Doyle	273,509		259,782		132,127
Steve R. Secrist	39,223		—		—
Marla D. Mellies	15,428		17,869		16,314
Philip K. Bussey	—		—		—