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

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

Overview

Puget Energy is an energy services holding company and substantially all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG). Puget LNG was formed on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. All of Puget Energy's common stock is indirectly owned by Puget Holdings, LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation. Puget Energy and PSE are collectively referred to herein as “the Company.”

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

Factors and Trends Affecting PSE's Performance

The principal business, economic and other factors that affect PSE's operations and financial performance include:

The rates PSE is allowed to charge for its services;

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

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

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

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

Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;

Availability and access to capital and the cost of capital;

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

Wholesale commodity prices of electricity and natural gas;

Increasing capital expenditures with additional depreciation and amortization;

Bonus depreciation and the impact on rate base;

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

Federal, state, and local taxes.

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

Regulation of PSE Rates and Recovery of PSE Costs

PSE's regulatory requirements and operational needs require the investment of substantial capital in 2017 and future years. As PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). The Washington Commission has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition. Accordingly, the Company will need to seek rate relief on a regular and frequent basis in the foreseeable future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of ~~cost effective,~~cost-effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment is not reasonable or prudent, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

General Rate Case Filing

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

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

fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has requested procedures for an Expedited Rate Filing (ERF) that can

be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects.

On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by the Washington Commission, would resolve all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also recommends a combined electric tariff change that would result in a net increase of $20.2 million, or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million, or 3.8%. The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement.

Decoupling Filings

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

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

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

On April 28, 2017, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2017. The overall changes represent a rate increase for electric customers of $41.9 million, or 2.0%, annually, and a rate increase for natural gas customers of $22.4 million, or 2.4%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2016. As a result, PSE filed with the Washington Commission a reduction in electric decoupling deferral and revenue of ~~$11.4~~$11.9 million and a reduction in natural gas decoupling deferral and revenue of ~~$2.1~~$2.2 million. This was included as a reduction to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2017 rate increase is $47.4 million for natural gas revenue that was accrued through December 31, 2016. The amount not recovered in 2017 may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

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

Other Proceedings

Microsoft

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

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

Voluntary Long-Term Renewable Energy

On September 28, 2016, the Washington Commission approved PSE's tariff revision to create an additional voluntary renewable energy product, effective September 30, 2016. This provides customers with energy choices to help them meet their sustainability goals. Incremental costs of the program will be allocated to the voluntary participants of the program as is the case with PSE’s existing Green Power programs. PSE initially offered this service, Green Direct, to larger customers (aggregated annual loads greater than 10,000,000 kWh) and government customers. Approximately 135 MW of new wind generation facilities will be constructed in the region by a developer under contract to PSE which will meet the demand for this voluntary renewable energy product project.

Electric Rates

Power Cost Adjustment Mechanism

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

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



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

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



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

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

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

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

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

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

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

On September 30, 2016, PSE filed an accounting petition with the Washington Commission which requests deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested is January 1, 2017 through December 31, 2017 when rates go into effect from PSE's 2017 GRC. On November 10, 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition.

For the ~~six~~nine months ended ~~June~~September 30, 2017, PSE under recovered its power costs by ~~$8.6~~$8.9 million of which no amount was apportioned to customers. This compares to an ~~under~~over recovery of power costs of ~~$3.1~~$1.4 million for the ~~six~~nine months ended ~~June~~September 30, 2016 of which no amounts were apportioned to customers. ~~Load~~Although load increased in 2017 compared to 2016 ~~which~~that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, ~~this~~the year over year change was due to the ~~new~~ 2017 mechanism ~~which~~where fixed production costs, other costs and adjustments are no longer included. The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate. The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate.

Electric Conservation Rider

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

Electric Property Tax Tracker Mechanism

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

Federal Incentive Tracker Tariff

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

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

Residential Exchange Benefit

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

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

Power Cost Update Compliance Filing

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

Natural Gas Rates

Natural Gas Conservation Rider

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

Natural Gas Property Tax Tracker Mechanism

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

Natural Gas Cost Recovery Mechanism

On ~~June 1,~~October 26, 2017, ~~PSE filed with~~ the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2017. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system. The impact to the CRM rates is an annual revenue increase of ~~$5.4~~$4.9 million, or ~~0.6%~~0.5%, annually.

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

Purchased Gas Adjustment

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

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

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

Other Factors and Trends

Access to Debt Capital

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

were scheduled to mature in 2019 and Puget Energy's senior secured credit facility ~~matures~~to mature in 2018. ~~For additional~~In October 2017, PSE and Puget Energy each entered into new 5 year credit facilities that replaced the current facilities and are scheduled to mature in October 2022. Additional information ~~see discussion~~ on credit facilities is set forth below in ~~Part 1, Item 2,~~the “Puget Sound Energy - Credit Facilities” and "Puget Energy - Credit Facility". sections.

Regulatory Compliance Costs and Expenditures

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

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

Other Challenges and Strategies

Competition

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

Results of Operations

Puget Sound Energy

Non-GAAP Financial Measures - Electric and Natural Gas Margins

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

Electric Margin

Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory. The following table displays the details of PSE's electric margin changes:


Electric Margin	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change			2017			2016			Change			2017			2016			Change
Electric operating revenue:
Residential sales	$	253,011		$	231,345		$	21,666		$	637,834		$	576,176		$	61,658		$	239,279		$	224,987		$	14,292		$	877,112		$	801,163		$	75,949
Commercial sales	202,738			197,668			5,070			441,070			429,394			11,676			215,392			214,632			760			656,462			644,025			12,437
Industrial sales	25,844			24,975			869			55,581			54,677			904			27,836			29,740			(1,904		)	83,417			84,417			(1,000		)
Other retail sales	4,801			4,868			(67		)	9,695			10,202			(507		)	4,839			5,031			(192		)	14,534			15,234			(700		)
Total retail sales	486,394			458,856			27,538			1,144,180			1,070,449			73,731			487,346			474,390			12,956			1,631,525			1,544,839			86,686
Transportation sales	2,651			2,779			(128		)	5,714			5,622			92			3,422			2,464			958			9,136			8,086			1,050
Sales to other utilities and marketers	5,979			10,729			(4,750		)	14,687			17,538			(2,851		)	23,716			20,494			3,222			38,404			38,032			372
Decoupling revenue	24,358			15,783			8,575			11,581			34,476			(22,895		)	13,310			(277		)	13,587			24,889			34,199			(9,310		)
Other decoupling revenue¹	(4,682		)	4,538			(9,220		)	(7,698		)	(2,663		)	(5,035		)	(4,008		)	(11,863		)	7,855			(11,704		)	(14,525		)	2,821
Other	15,107			4,467			10,640			30,328			1,921			28,407			13,757			10,113			3,644			44,085			12,033			32,052
Total electric operating revenues²	529,807			497,152			32,655			1,198,792			1,127,343			71,449			537,543			495,321			42,222			1,736,335			1,622,664			113,671
Minus electric energy costs:
Purchased electricity²	129,799			118,551			11,248			309,381			261,448			47,933			115,881			94,849			21,032			425,263			356,296			68,967
Electric generation fuel²	34,163			40,930			(6,767		)	85,473			95,123			(9,650		)	66,584			70,503			(3,919		)	152,057			165,627			(13,570		)
Residential exchange²	(15,121		)	(13,376		)	(1,745		)	(38,568		)	(33,516		)	(5,052		)	(14,246		)	(15,577		)	1,331			(52,814		)	(49,093		)	(3,721		)
Total electric energy costs	148,841			146,105			2,736			356,286			323,055			33,231			168,219			149,775			18,444			524,506			472,830			51,676
Electric margin³	$	380,966		$	351,047		$	29,919		$	842,506		$	804,288		$	38,218		$	369,324		$	345,546		$	23,778		$	1,211,829		$	1,149,834		$	61,995

Electric Energy Sales, MWh
Residential sales	2,227,999			2,062,717			165,282			5,704,408			5,175,549			528,859			2,081,223			1,997,675			83,548			7,785,631			7,173,224			612,407
Commercial sales	2,129,016			2,083,751			45,265			4,512,612			4,370,929			141,683			2,272,185			2,266,420			5,765			6,784,797			6,637,349			147,448
Industrial sales	289,516			284,081			5,435			597,596			591,171			6,425			316,051			334,108			(18,057		)	913,647			925,280			(11,633		)
Other retail sales	20,840			21,362			(522		)	44,338			46,096			(1,758		)	19,879			23,271			(3,392		)	64,217			69,366			(5,149		)
Total energy sales to customers	4,667,371			4,451,911			215,460			10,858,954			10,183,745			675,209			4,689,338			4,621,474			67,864			15,548,292			14,805,219			743,073

___________________


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


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


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

Three Months Ended ~~June~~September 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased ~~$32.7~~$42.2 million primarily due to decoupling revenue of $13.6 million, higher retail sales of ~~$27.5~~$13.0 million, other decoupling revenue of $7.9 million and other electric operating revenues of ~~$10.6 million and decoupling revenue of $8.6 million; partially offset by a decrease in other decoupling revenue of $9.2~~$3.6 million. These items are discussed in detail below.

Electric retail sales increased ~~$27.5~~$13.0 million primarily due to a ~~$22.2~~$7.0 million increase in retail electricity usage of ~~215,460~~67,864 Megawatt Hour (MWhs) related to average retail customer growth of 13,828 customers, or 1.2%; and an increase in rates of ~~$5.3~~$6.0 million.

Decoupling revenue increased ~~$8.6~~$13.6 million due to an increase of ~~$16.2~~$15.7 million ofin decoupling revenue associated with the fixed cost ~~deferrals previously recorded within~~deferral of the PCA mechanism in 2017. This was partially offset by ~~a decrease of $7.6~~$2.1 million ~~associated with less decoupled revenues~~ in ~~excess of actual customer billings as~~lower decoupling deferrals in 2017 compared to ~~2016.~~2016 due to higher electricity usage, as noted above.

Other decoupling revenue ~~decreased $9.2~~increased $7.9 million due to ~~increased~~reduced sharing of rate of return (ROR) excess earnings of ~~$7.4~~$10.2 million ~~and~~from over earnings in 2016 as compared to no earnings sharing in 2017. This was partially offset by an increase of decoupling cash collections of ~~$2.5~~$1.1 million as compared to ~~2016.~~2016 due to an additional $9.0 million being set into rates.

Other electric operating revenue increased ~~$10.6~~$3.6 million primarily due to generation of a ~~PTC~~production tax credit (PTC) deferral of ~~$5.7~~$5.0 million in 2016 as compared to no PTC deferral in 2017 ~~and an increase~~since the PTC generation period expired in the first quarter of 2017. This was partially offset by a decrease in net ~~non-core~~wholesale natural gas sales of ~~$5.0~~$1.8 million.

Electric Energy Costs

Purchased electricity expense increased ~~$11.2~~$21.0 million primarily due to a ~~$9.6~~$13.9 million increase primarily related to ~~firm~~long-term purchases ~~from TransAlta Centralia~~ and a ~~$3.7~~$4.9 million increase in energy imbalance market (EIM) ~~purchases compared to 2016.~~purchases. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. ~~The increases were partially offset~~Additionally, lower overall wind production of 21.3% and lower production at the combustion turbines of 7.8% resulted in the need to purchase power. PSE began participating in the EIM operated by ~~a decrease~~the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of ~~$4.4 million of secondary purchases.~~electricity demand and generation resources.

Electric generation fuel expense decreased ~~$6.8~~$3.9 million due to a number of factors including a ~~$2.2~~$3.3 million decrease in ~~financial losses on~~the total cost of natural gas ~~fuel~~burned driven by lower volumes burned in 2017 as compared to ~~2016,~~2016. Also contributing to the decrease in fuel costs is a ~~$2.1~~$3.4 million decrease in the cost of coal burned from lower average prices offset by a $1.9 million increase in the lower of cost or market inventory adjustment for coal recorded in 2017 compared to 2016, and a $1.4 million decrease in the cost of coal burned. The decrease in the cost of coal burned was driven by a decrease in the average price of coal in 2017 compared to 2016 and offset by an increase in the volume of coal burned in 2017. 2016.

~~Six~~Nine Months Ended ~~June~~September 30, 2017 compared to 2016

Electric Operating Revenue

Electric operating revenues increased ~~$71.4~~$113.7 million primarily due to higher retail sales of ~~$73.7~~$86.7 million, ~~and~~ other operating revenues of ~~$28.4~~$32.1 million and other decoupling adjustments of $2.8 million; partially offset by decreases in decoupling revenue of ~~$22.9 million and other decoupling adjustments of $5.0~~$9.3 million. These items are discussed in detail below.

Electric retail sales increased ~~$73.7~~$86.7 million primarily due to a ~~$71.0~~$77.5 million increase in retail electricity usage of ~~675,209 Megawatt Hour (MWhs)~~743,073 MWhs related to a 28.0% increase in heating degree days; and an increase in rates of ~~$2.8~~$9.2 million.

Decoupling revenue decreased ~~$22.9~~$9.3 million due to ~~a decrease~~$19.8 million in ~~allowed decoupled revenues~~lower decoupling deferrals in ~~excess of actual customer billings as~~2017 compared to ~~2016.~~2016 due to higher electricity usage, as noted above. This was partially offset by an increase of $10.5 million in decoupling revenue associated with the fixed cost deferral of the PCA mechanism in 2017.

Other decoupling revenue ~~decreased $5.0~~increased $2.8 million primarily due to ~~an increase~~decreases in ~~decoupling cash collections~~ROR excess earnings sharing of ~~$6.3 million;~~$8.6 million due to no expectation to over earn in 2017 and 24-month revenue reserve of $1.6 million from no reserve in 2017. This was partially offset by a ~~decrease~~$7.4 million increase of ~~24-month revenue reserve of $2.0 million~~decoupling cash collections as compared to ~~2016.~~2016 due to an additional $9.0 million being set into rates.

Other electric operating revenue increased ~~$28.4~~$32.1 million primarily due to an increase in net ~~non-core~~wholesale natural gas sales of ~~$19.1~~$17.3 million and a PTC deferral of ~~$10.8~~$15.8 million in 2016 as compared to no PTC deferral in 2017 since the PTC generation period expired in the first quarter of 2017.

Electric Energy Costs

Purchased electricity expense increased ~~$47.9~~$69.0 million primarily due to a ~~$19.7~~$45.5 million increase related to ~~firm~~long-term purchases, ~~from TransAlta Centralia, an increase of $9.4 million of secondary purchases, an $8.4~~a $13.3 million increase in EIM purchases, and ana $8.3 million increase in the power exchange contract with Pacific Gas & Electric Company. These increases were due to additional load requirements and lower costs to buy on the open market compared to generating power. Additionally, lower overall wind production of 17.4% and lower production at the combustion turbines of 26.3% resulted in the need to purchase power. PSE began participating in the EIM operated by the California Independent System Operator on October 1, 2016. Participation is expected to reduce costs for PSE customers, enhance system reliability, integrate variable energy resources and leverage geographic diversity of electricity demand and generation resources.

Electric generation fuel expense decreased ~~$9.7~~$13.6 million primarily due to a ~~$7.8 million decrease in financial losses on natural gas fuel in 2017 as compared to 2016 and a $2.1~~$10.7 million decrease in the total cost of natural gas burned driven by lower volumes burned offset by an increase in the average price of the natural gas burned and a $2.9 million decrease in the cost ~~or market inventory adjustment for~~of coal ~~recorded~~burned due to a lower average prices of coal burned in 2017 compared to 2016.

Residential exchange credits increased ~~$5.1~~$3.7 million resulting from ~~higher Residential Exchange Program (REP) credits associated with the BPA REP settlement.~~increased electricity usage as rates remain consistent in both periods. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income. The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE. The program is administered by the BPA. Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

Natural Gas Margin

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


Natural Gas Margin	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change			2017			2016			Change			2017			2016			Change
Natural gas operating revenue:
Residential sales	$	120,052		$	92,099		$	27,953		$	401,933		$	309,830		$	92,103		$	65,793		$	66,480		$	(687	)	$	467,725		$	376,310		$	91,415
Commercial sales	55,370			44,125			11,245			158,099			125,273			32,826			36,617			36,862			(245		)	194,716			162,135			32,581
Industrial sales	4,281			3,627			654			11,868			10,393			1,475			3,390			3,349			41			15,258			13,742			1,516
Total retail sales	179,703			139,851			39,852			571,900			445,496			126,404			105,800			106,691			(891		)	677,699			552,187			125,512
Transportation sales	5,385			5,018			367			10,932			10,111			821			5,285			4,897			388			16,218			15,007			1,211
Decoupling revenue	2,888			15,979			(13,091		)	(3,357		)	36,030			(39,387		)	4,840			3,709			1,131			1,482			39,739			(38,257		)
Other decoupling revenue¹	(11,024		)	(297		)	(10,727		)	(5,617		)	(10,661		)	5,044			(7,315		)	(3,904		)	(3,411		)	(12,932		)	(14,565		)	1,633
Other	3,153			2,892			261			6,311			5,875			436			2,906			3,065			(159		)	9,218			8,941			277
Total natural gas operating revenues²	180,105			163,443			16,662			580,169			486,851			93,318			111,516			114,458			(2,942		)	691,685			601,309			90,376
Minus purchased natural gas energy costs²	63,183			48,273			14,910			215,984			171,376			44,608			32,224			34,041			(1,817		)	248,208			205,418			42,790
Natural gas margin³	$	116,922		$	115,170		$	1,752		$	364,185		$	315,475		$	48,710		$	79,292		$	80,417		$	(1,125	)	$	443,477		$	395,891		$	47,586

Natural Gas Volumes
(Therms in Thousands):
Residential	98,526			72,506			26,020			370,175			286,531			83,644			42,150			44,650			(2,500		)	412,325			331,180			81,145
Commercial firm	52,135			41,387			10,748			162,585			127,467			35,118			31,861			31,629			232			194,446			159,096			35,350
Industrial firm	5,241			4,394			847			14,397			12,389			2,008			4,048			3,626			422			18,444			16,015			2,429
Interruptible	12,627			8,582			4,045			27,044			24,377			2,667			6,877			9,452			(2,575		)	33,921			33,829			92
Total retail natural gas volumes, therms	168,529			126,869			41,660			574,201			450,764			123,437			84,936			89,357			(4,421		)	659,136			540,120			119,016
Transportation volumes	56,261			56,164			97			119,049			118,249			800			53,992			52,298			1,694			173,042			170,548			2,494
Total natural gas volumes	224,790			183,033			41,757			693,250			569,013			124,237			138,928			141,655			(2,727		)	832,178			710,668			121,510

_______________


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


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


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

Three Months Ended ~~June~~September 30, 2017 compared to 2016

Natural Gas Operating Revenue

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

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

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

Nine Months Ended September 30, 2017 compared to 2016

Natural Gas Operating Revenue

Natural gas operating revenue increased ~~$16.7~~$90.4 million primarily due to an increase of $39.9 million in total retail sales due to an increase of natural gas usage; partially offset by a $13.1 million reduction in decoupling revenue and a decrease of $10.7 million in other decoupling revenue. These items are discussed in detail below.

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

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

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

~~Natural Gas Energy Costs~~

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

~~Six Months Ended June 30, 2017 compared to 2016~~

~~Natural Gas Operating Revenue~~

~~Natural gas operating revenue~~ ~~increased $93.3 million primarily due to an increase of $126.4~~$125.5 million in total retail sales due to additional natural gas usage and an increase in other decoupling revenue of ~~$5.0~~$1.6 million; partially offset by a ~~$39.4~~$38.3 million reduction in decoupling revenue. These items are discussed in detail below.

Natural gas retail sales revenue increased ~~$126.4~~$125.5 million primarily due to an increase of ~~$122.0~~$121.7 million from an additional ~~123,437 of~~121,510 therms sold related to a 28.0% increase in heating degree days; and an increase of ~~$4.4~~$3.8 million due to rate adjustments.

Decoupling revenue decreased ~~$39.4~~$38.3 million due to ~~a decrease~~lower load volumes in 2016, which caused actual revenue to be below the allowed ~~decoupled revenues~~revenue, resulting in ~~excess~~higher decoupling revenue of $39.7 million. In 2017, higher load volumes caused actual ~~customer billings as compared~~revenue to ~~the prior period.~~be closer to allowed revenue resulting in lower decoupling revenue of $1.5 million.

Other decoupling revenue increased ~~$5.0~~$1.6 million primarily due to ~~the recognition~~a $22.9 million reversal of previously deferred revenues related to the 24-month revenue ~~reserve, previously unrecognized, of $20.2 million.~~reserve. The increase was partially offset by an increase in decoupling cash collections of ~~$13.1~~$13.0 million due to an additional $6.0 million being set in rates and ~~an increase in~~increased ROR excess ~~earning~~earnings sharing of ~~$2.1~~$8.2 million ~~as compared to 2016.~~of which $10.1 million was accrued for over earnings in 2017.

Natural Gas Energy Costs

Purchased natural gas expense increased ~~$44.6~~$42.8 million ~~primarily due~~directly related to ana 22.7% increase in natural gas usage.

Other Operating Expenses and Other Income (Deductions)

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


Puget Sound Energy	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change			2017			2016			Change			2017			2016			Change
Operating expenses:
Net unrealized (gain) loss on derivative instruments	$	3,834		$	(46,724	)	$	50,558		$	23,121		$	(63,546	)	$	86,667		$	(23	)	$	6,327		$	(6,350	)	$	23,098		$	(57,218	)	$	80,316
Utility operations and maintenance	145,555			138,018			7,537			297,618			284,008			13,610			141,003			138,265			2,738			438,622			422,273			16,349
Non-utility expense and other	9,374			8,822			552			17,865			17,856			9			9,994			8,620			1,374			27,857			26,474			1,383
Depreciation and amortization	119,457			111,273			8,184			234,710			218,787			15,923			120,829			110,022			10,807			355,538			328,809			26,729
Conservation amortization	25,691			22,540			3,151			60,453			55,751			4,702			25,395			21,800			3,595			85,847			77,551			8,296
Taxes other than income taxes	77,032			67,871			9,161			195,731			170,163			25,568			66,367			65,268			1,099			262,099			235,431			26,668
Other income (deductions):
Other income	6,126			7,077			(951		)	12,086			13,052			(966		)	6,778			6,131			647			18,861			19,184			(323		)
Other expense	(2,042		)	(2,122		)	80			(3,257		)	(3,462		)	205			(2,878		)	(5,025		)	2,147			(6,134		)	(8,488		)	2,354
Interest expense	(57,436		)	(58,044		)	608			(115,723		)	(116,460		)	737			(56,745		)	(58,212		)	1,467			(172,467		)	(174,673		)	2,206
Income tax expense	22,794			38,002			(15,208		)	94,591			109,140			(14,549		)	14,424			8,393			6,031			109,015			117,533			(8,518		)

Three Months Ended ~~June~~September 30, 2017 compared to 2016

Other Operating Expenses

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

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

Other Income, Interest Expense and Income Tax Expense

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

Nine Months Ended September 30, 2017 compared to 2016

Other Operating Expenses

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

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

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

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

~~Other Income, Interest Expense and Income Tax Expense~~

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

~~Six Months Ended June 30, 2017 compared to 2016~~

~~Other Operating Expenses~~

~~Net unrealized (gain) loss on derivative instruments~~ ~~decreased $86.7~~$80.3 million to a loss of $23.1 ~~million. The net loss for the six months ended June 30, 2017~~million of which $57.2 million was ~~comprised~~due to decreases in average forward market prices of ~~a loss of $21.9 million related to~~wholesale electricity and natural gas, ~~for power derivative instruments~~ and ~~a $1.2~~$23.1 million loss related to electricity derivative instruments. This compares to a gain of $50.8 million related to natural gas for power derivative instruments and a gain of $12.7 million related to electricity derivative instruments during the six months ended June 30, 2016. The overall loss was primarily due to a decrease in ~~natural gas and wholesale electricity forward prices from June 30, 2016 to June 30, 2017. The majority~~settlements of ~~the Company's hedging portfolio is made up of purchase transactions.~~contracts with previously unrealized losses.

Utility operations and maintenance expense increased ~~$13.6~~$16.3 million, which was primarily due to the following: increases in administrative and general and customer service expense of ~~$20.3~~$21.9 million primarily due to ~~customer records, collections, low income programs, rents, employee pension~~$7.1 million of rent expense primarily at the corporate office locations, $5.3 million expense primarily for liability claims and insurance premium, $4.6 million of pensions and benefits ~~injuries and damage, electric maintenance~~expense, $3.9 million of general plant maintenance expense and $3.1 million of outside services ~~expense.~~employed expenses. This was partially offset by a decrease in electric transmission ~~distribution~~ and ~~natural gas operation~~distribution expense of ~~$6.5 million primarily related to distribution operations supervision and engineering, meter, distribution maintenance of underground lines and monitoring expenses and operation of load dispatch.~~$8.4 million.

Depreciation and amortization expense increased ~~$15.9~~$26.7 million primarily due to ~~$8.0 million of depreciation expense due to net additions of $176.2 million,~~ an increase of ~~$3.3 million due to net additions of $186.0 million of natural gas distribution assets and an increase of $7.7~~$11.6 million of amortization expense related to an increase of computer software assets, $8.7 million of depreciation expense due to net additions of $253.7 million of electric transmission, distribution and general assets and an increase of $5.0 million of depreciation expense due to net additions of $174.8 million of natural gas distribution assets.

Taxes other than income taxes increased ~~$25.6~~$26.7 million primarily due to ~~an increase of $8.9 million in property taxes due to increased revenue and load, an increase~~increases in municipal taxes of ~~$8.9~~$9.2 million ~~due~~and state excise taxes of $8.5 million both related to increased revenue and an increase of $8.8 million in ~~state excise~~property taxes ~~of $7.8 million.~~related to increased property values and expected tax rates.

Other Income, Interest Expense and Income Tax Expense

Income tax expense decreased ~~$14.5~~$8.5 million primarily driven by lower pre-tax book income.

Puget Energy

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


Benefit/(Expense)	Three Months Ended June 30,									Six Months Ended June 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(Dollars in Thousands)	2017			2016			Change			2017			2016			Change			2017			2016			Change			2017			2016			Change
PSE net income	$	50,654		$	80,900		$	(30,246	)	$	193,746		$	237,406		$	(43,660	)	$	29,100		$	18,977		$	10,123		$	222,846		$	256,382		$	(33,536	)
Non-utility expense and other	3,231			3,644			(413		)	6,526			7,043			(517		)	2,675			3,912			(1,237		)	9,200			10,956			(1,756		)
Other income (deductions)	136			—			136			137			—			137			374			(316		)	690			512			(316		)	828
Non-hedged interest rate swap (expense)	—			(359		)	359			28			(1,213		)	1,241			—			563			(563		)	28			(651		)	679
Interest expense¹	(28,417		)	(28,029		)	(388		)	(56,538		)	(56,067		)	(471		)	(28,913		)	(28,384		)	(529		)	(85,451		)	(84,451		)	(1,000		)
Income tax benefit (expense)	9,671			8,397			1,274			18,926			18,570			356			9,600			7,583			2,017			28,527			26,154			2,373
Puget Energy net income (loss)	$	35,275		$	64,553		$	(29,278	)	$	162,825		$	205,739		$	(42,914	)	$	12,836		$	2,335		$	10,501		$	175,662		$	208,074		$	(32,412	)



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



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



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	/ /



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



		Page
Definitions		3
Filing Format		4
Forward-Looking Statements		4

Part I.	Financial Information	5

Item 1.	Financial Statements	5
	Puget Energy, Inc.
	Consolidated Statements of Income – Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	5
	Consolidated Statements of Comprehensive Income – Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	6
	Consolidated Balance Sheets – ~~June~~September 30, 2017 and December 31, 2016	7
	Consolidated Statements of Cash Flows – ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	8

	Puget Sound Energy, Inc.
	Consolidated Statements of Income – Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	9
	Consolidated Statements of Comprehensive Income – Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	10
	Consolidated Balance Sheets – ~~June~~September 30, 2017 and December 31, 2016	11
	Consolidated Statements of Cash Flows – ~~Six~~Nine Months Ended ~~June~~September 30, 2017 and 2016	13

	Notes
	Combined Notes to Consolidated Financial Statements	14

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3435

Item 3.	Quantitative and Qualitative Disclosure About Market Risk	5253

Item 4.	Controls and Procedures	53

Part II.	Other Information	54

Item 1.	Legal Proceedings	54

Item 1A.	Risk Factors	54

Item 6. 5.	~~Exhibits~~ Other Information	54

~~Signatures~~Item 6.	Exhibits	55

Exhibit Index		56

Signatures		57



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



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



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



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



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



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



●	Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;
●	Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or by products of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
●	Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;
●	Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
●	Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
●	Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●	Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE's ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●	Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
●	The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
●	PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●	Electric plant generation and transmission system outages, which can have an adverse impact on PSE's expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
●	The ability to restart generation following a regional transmission disruption;
●	Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●	Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●	Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●	Variable wind conditions, which can impact PSE's ability to generate electricity from wind facilities;
●	The ability to renew contracts for electric and natural gas supply and the price of renewal;
●	Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●	General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
●	The loss of significant customers, changes in the business of significant customers or the condemnation of PSE's facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE's services;
●	The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE's customer service, generation, distribution and transmission;
●	Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●	Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
●	The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;
●	The ability to maintain effective internal controls over financial reporting and operational processes;
●	Changes in Puget Energy's or PSE's credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally; and
●	Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE's retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS	PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS						PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) ASSETS

	June 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Utility plant (at original cost, including construction work in progress of $505,334 and $420,278, respectively):
Utility plant (at original cost, including construction work in progress of $598,790 and $420,278, respectively):
Electric plant	$	7,824,350		$	7,673,772		$	7,918,877		$	7,673,772
Natural gas plant	3,178,998			3,051,586			3,253,977			3,051,586
Common plant	673,542			594,994			738,409			594,994
Less: Accumulated depreciation and amortization	(2,321,677		)	(2,161,796		)	(2,409,508		)	(2,161,796		)
Net utility plant	9,355,213			9,158,556			9,501,755			9,158,556
Other property and investments:
Goodwill	1,656,513			1,656,513			1,656,513			1,656,513
Other property and investments	146,316			106,418			166,996			106,418
Total other property and investments	1,802,829			1,762,931			1,823,509			1,762,931
Current assets:
Cash and cash equivalents	7,805			28,878			6,768			28,878
Restricted cash	12,048			12,418			9,302			12,418
Accounts receivable, net of allowance for doubtful accounts of $9,977 and $9,798, respectively	251,304			329,375
Accounts receivable, net of allowance for doubtful accounts of $6,088 and $9,798, respectively							232,699			329,375
Unbilled revenue	115,945			234,053			126,252			234,053
Purchased gas adjustment receivable	—			2,785			—			2,785
Materials and supplies, at average cost	100,772			106,378			108,814			106,378
Fuel and natural gas inventory, at average cost	55,598			58,181			60,645			58,181
Unrealized gain on derivative instruments	16,078			54,341			16,605			54,341
Prepaid expense and other	29,146			43,046			35,655			43,046
Power contract acquisition adjustment gain	15,544			33,413			15,932			33,413
Total current assets	604,240			902,868			612,672			902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,598			72,038			71,566			72,038
Power cost adjustment mechanism	4,505			4,531			4,540			4,531
Regulatory assets related to power contracts	20,737			22,613			19,998			22,613
Other regulatory assets	1,004,297			1,034,348			1,014,796			1,034,348
Unrealized gain on derivative instruments	4,505			8,738			2,877			8,738
Power contract acquisition adjustment gain	168,040			241,648			163,588			241,648
Other	62,589			58,109			65,138			58,109
Total other long-term and regulatory assets	1,336,271			1,442,025			1,342,503			1,442,025
Total assets	$	13,098,553		$	13,266,380		$	13,280,439		$	13,266,380

PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)	PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)						PUGET ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) (Unaudited)

	Six Months Ended June 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Operating activities:
Net income (loss)	$	162,825		$	205,739		$	175,662		$	208,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	234,710			218,787			355,538			328,809
Conservation amortization	60,453			55,751			85,847			77,551
Deferred income taxes and tax credits, net	75,665			90,018			81,899			90,828
Net unrealized (gain) loss on derivative instruments	22,980			(65,414		)	22,957			(60,785		)
AFUDC – equity	(6,766		)	(7,048		)	(11,266		)	(10,769		)
Funding of pension liability	(18,000		)	(9,000		)	(18,000		)	(24,000		)
Regulatory assets and liabilities	(44,731		)	(120,615		)	(83,370		)	(138,096		)
Other long-term assets and liabilities	11,194			14,519			8,275			30,766
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	196,179			184,595			204,477			175,627
Materials and supplies	5,606			(18,594		)	(2,436		)	(28,448		)
Fuel and natural gas inventory	2,473			4,974			(2,789		)	(3,222		)
Prepayments and other	13,900			(2,738		)	7,391			(29,352		)
Purchased gas adjustment	13,765			(1,027		)	8,569			(10,743		)
Accounts payable	(49,478		)	(64,132		)	(31,027		)	(22,874		)
Taxes payable	(9,296		)	(13,230		)	(30,074		)	(36,411		)
Other	(5,809		)	4,650			(2,983		)	23,391
Net cash provided by (used in) operating activities	665,670			477,235			768,670			570,346
Investing activities:
Construction expenditures – excluding equity AFUDC	(496,652		)	(303,834		)	(761,968		)	(507,703		)
Restricted cash	370			(2,179		)	3,116			(1,391		)
Other	(6,642		)	(4,851		)	5,796			(1,781		)
Net cash provided by (used in) investing activities	(502,924		)	(310,864		)	(753,056		)	(510,875		)
Financing activities:
Change in short-term debt, net	(240,763		)	(123,004		)	(106,763		)	12,996
Dividends paid	(132		)	(74,268		)	(17,543		)	(111,592		)
Proceeds from long-term debt and bonds issued	48,073			—			70,583			—
Other	9,003			7,426			15,999			13,479
Net cash provided by (used in) financing activities	(183,819		)	(189,846		)	(37,724		)	(85,117		)
Net increase (decrease) in cash and cash equivalents	(21,073		)	(23,475		)	(22,110		)	(25,646		)
Cash and cash equivalents at beginning of period	28,878			42,494			28,878			42,494
Cash and cash equivalents at end of period	$	7,805		$	19,019		$	6,768		$	16,848
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	$	163,228		$	164,310		$	239,566		$	241,351
Cash payments (refunds) for income taxes	—			—			1,649			—
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	$	54,419		$	47,151		$	87,456		$	58,278


~~(3)~~	~~Accounting for Derivative Instruments and Hedging Activities~~

PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) CAPITALIZATION AND LIABILITIES	PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) CAPITALIZATION AND LIABILITIES						PUGET ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) (Unaudited) CAPITALIZATION AND LIABILITIES

	June 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding	$	—		$	—		$	—		$	—
Additional paid-in capital	3,308,957			3,308,957			3,308,957			3,308,957
Retained earnings	576,161			413,468			571,588			413,468
Accumulated other comprehensive income (loss), net of tax	(33,046		)	(33,712		)	(33,312		)	(33,712		)
Total common shareholder’s equity	3,852,072			3,688,713			3,847,233			3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,162,000			3,362,000			3,164,412			3,362,000
Pollution control bonds	161,860			161,860			161,860			161,860
Junior subordinated notes	250,000			250,000			250,000			250,000
Long-term debt	1,860,554			1,812,480			1,883,064			1,812,480
Debt discount, issuance costs and other	(227,766		)	(234,679		)	(224,336		)	(234,679		)
Total long-term debt	5,206,648			5,351,661			5,235,000			5,351,661
Total capitalization	9,058,720			9,040,374			9,082,233			9,040,374
Current liabilities:
Accounts payable	245,171			317,043			296,659			317,043
Short-term debt	5,000			245,763			139,000			245,763
Current maturities of long-term debt	202,412			2,412			200,000			2,412
Purchased gas adjustment payable	10,980			—			5,784			—
Accrued expenses:
Taxes	102,132			111,428			81,354			111,428
Salaries and wages	39,245			49,749			41,121			49,749
Interest	74,046			73,610			79,213			73,610
Unrealized loss on derivative instruments	44,031			44,310			49,820			44,310
Power contract acquisition adjustment loss	2,983			3,159			2,850			3,159
Other	87,756			71,996			81,486			71,996
Total current liabilities	813,756			919,470			977,287			919,470
Other long-term and regulatory liabilities:
Deferred income taxes	1,646,515			1,570,931			1,652,573			1,570,931
Unrealized loss on derivative instruments	18,237			16,261			15,578			16,261
Regulatory liabilities	620,950			654,622			611,899			654,622
Regulatory liabilities related to power contracts	183,583			275,061			179,519			275,061
Power contract acquisition adjustment loss	17,754			19,454			17,148			19,454
Other deferred credits	739,038			770,207			744,202			770,207
Total other long-term and regulatory liabilities	3,226,077			3,306,536			3,220,919			3,306,536
Commitments and contingencies (Note 8)


	June 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Capitalization:
Common shareholder’s equity:
Common stock $0.01 par value, 150,000,000 shares authorized, 85,903,791 shares outstanding	$	859		$	859		$	859		$	859
Additional paid-in capital	3,275,105			3,275,105			3,275,105			3,275,105
Retained earnings	501,967			359,795			486,095			359,795
Accumulated other comprehensive income (loss), net of tax	(140,014		)	(145,511		)	(138,191		)	(145,511		)
Total common shareholder’s equity	3,637,917			3,490,248			3,623,868			3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,162,000			3,362,000			3,164,412			3,362,000
Pollution control bonds	161,860			161,860			161,860			161,860
Junior subordinated notes	250,000			250,000			250,000			250,000
Debt discount, issuance costs and other	(27,669		)	(28,974		)	(27,043		)	(28,974		)
Total long-term debt	3,546,191			3,744,886			3,549,229			3,744,886
Total capitalization	7,184,108			7,235,134			7,173,097			7,235,134
Current liabilities:
Accounts payable	245,171			317,043			296,659			317,043
Short-term debt	5,000			245,763			139,000			245,763
Current maturities of long-term debt	202,412			2,412			200,000			2,412
Purchased gas adjustment payable	10,980			—			5,784			—
Accrued expenses:
Taxes	102,132			111,428			81,354			111,428
Salaries and wages	39,245			49,749			41,121			49,749
Interest	48,232			48,087			56,254			48,087
Unrealized loss on derivative instruments	44,031			44,170			49,820			44,170
Other	87,756			71,996			81,486			71,996
Total current liabilities	784,959			890,648			951,478			890,648
Other long-term and regulatory liabilities:
Deferred income taxes	1,829,508			1,732,390			1,844,886			1,732,390
Unrealized loss on derivative instruments	18,237			16,261			15,578			16,261
Regulatory liabilities	619,736			653,296			610,902			653,296
Other deferred credits	738,144			769,351			741,860			769,351
Total other long-term and regulatory liabilities	3,205,625			3,171,298			3,213,226			3,171,298
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$	11,174,692		$	11,297,080		$	11,337,801		$	11,297,080


(1)	Summary of Consolidation Policy


Puget Energy and Puget Sound Energy
	At June 30, 2017						At December 31, 2016					At September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Volumes		Assets¹		Liabilities²		Volumes	Assets¹		Liabilities²		Volumes		Assets¹		Liabilities²		Volumes	Assets¹		Liabilities²
Interest rate swap derivatives³	$	—	$	—	$	—	$450 million	$	—	$	141	$	—	$	—	$	—	$450 million	$	—	$	141
Electric portfolio derivatives	*		12,246		40,235		*	36,460		41,329		*		11,656		39,622		*	36,460		41,329
Natural gas derivatives (MMBtus)⁴	310.6 million		8,337		22,033		336.4 million	26,619		19,101		305.3 million		7,826		25,776		336.4 million	26,619		19,101
Total derivative contracts	**		$	20,583	$	62,268	**	$	63,079	$	60,571	**		$	19,482	$	65,398	**	$	63,079	$	60,571
Current	**		$	16,078	$	44,031	**	$	54,341	$	44,310	**		$	16,605	$	49,820	**	$	54,341	$	44,310
Long-term	**		4,505		18,237		**	8,738		16,261		**		2,877		15,578		**	8,738		16,261
Total derivative contracts	**		$	20,583	$	62,268	**	$	63,079	$	60,571	**		$	19,482	$	65,398	**	$	63,079	$	60,571


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


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


^*	Electric portfolio derivatives consist of electric generation fuel of ~~180.0~~165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of ~~1.9~~2.6 million Megawatt Hours (MWhs) at ~~June~~September 30, 2017, and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.



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


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


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	The carrying value includes debt issuances costs of ~~$30.4~~$29.1 million and $33.0 million for ~~June~~September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.


Puget Energy and	Fair Value						Fair Value						Fair Value						Fair Value
Puget Sound Energy	At June 30, 2017						At December 31, 2016						At September 30, 2017						At December 31, 2016
(Dollars in Thousands)	Level 2		Level 3		Total		Level 2		Level 3		Total		Level 2		Level 3		Total		Level 2		Level 3		Total
Assets:
Electric derivative instruments	$	7,793	$	4,453	$	12,246	$	30,666	$	5,794	$	36,460	$	7,106	$	4,550	$	11,656	$	30,666	$	5,794	$	36,460
Natural gas derivative instruments	4,737		3,600		8,337		23,316		3,303		26,619		3,794		4,032		7,826		23,316		3,303		26,619
Total assets	$	12,530	$	8,053	$	20,583	$	53,982	$	9,097	$	63,079	$	10,900	$	8,582	$	19,482	$	53,982	$	9,097	$	63,079
Liabilities:
Interest rate derivative instruments¹	$	—	$	—	$	—	$	141	$	—	$	141	$	—	$	—	$	—	$	141	$	—	$	141
Electric derivative instruments	36,425		3,810		40,235		36,507		4,822		41,329		36,482		3,140		39,622		36,507		4,822		41,329
Natural gas derivative instruments	19,889		2,144		22,033		16,423		2,678		19,101		23,998		1,778		25,776		16,423		2,678		19,101
Total liabilities	$	56,314	$	5,954	$	62,268	$	53,071	$	7,500	$	60,571	$	60,480	$	4,918	$	65,398	$	53,071	$	7,500	$	60,571


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


¹	Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of ~~$0.5 million and $(2.5)~~$0.9 million for the three months ended ~~June~~September 30, 2017 and 2016 ~~respectively~~.


²¹	Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of ~~$0.7~~$1.9 million and ~~$3.1~~$4.0 million for the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, respectively.


Puget Energy and Puget Sound Energy	Fair Value						Range			Fair Value						Range
(Dollars in Thousands)	Assets¹		Liabilities¹		Valuation Technique	Unobservable Input	Low	High	Weighted Average	Assets¹		Liabilities¹		Valuation Technique	Unobservable Input	Low		High		Weighted Average
Electric	$	4,453	$	3,810	Discounted cash flow	Power prices	$13.00 per MWh	$32.65 per MWh	$24.41 per MWh	$	4,550	$	3,140	Discounted cash flow	Power prices (per MWh)	$	8.54	$	28.98	$	17.99
Natural gas	$	3,600	$	2,144	Discounted cash flow	Natural gas prices	$1.47 per MMBtu	$3.14 per MMBtu	$2.41 per MMBtu	$	4,032	$	1,778	Discounted cash flow	Natural gas prices (per MMBtu)	$	0.38	$	3.09	$	2.75


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


Puget Energy
(Dollars in Thousands)
Valuation Date	Contract Name	Carrying Value		Fair Value		Write Down		Contract Name	Carrying Value		Fair Value		Write Down
September 30, 2017								Wells Hydro	$	10,621	$	9,609	$	1,012

March 31, 2017	Wells Hydro	$	14,879	$	13,067	$	1,812	Wells Hydro	$	14,879	$	13,067	$	1,812
	Rocky Reach	235,331		159,818		75,513		Rocky Reach	235,331		159,818		75,513
	Priest Rapids RP	5,665		2,657		3,008		Priest Rapids RP	5,665		2,657		3,008
Total impairment		$	255,875	$	175,542	$	80,333
Total year-to-date impairments													$	81,345



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


Puget Energy	Qualified Pension Benefits						SERP Pension Benefits				Other Benefits						Qualified Pension Benefits						SERP Pension Benefits				Other Benefits
	Three Months Ended June 30,																Three Months Ended September 30,
(Dollars in Thousands)	2017			2016			2017		2016		2017			2016			2017			2016			2017		2016		2017			2016
Components of net periodic benefit cost:
Service cost	$	5,023		$	4,605		$	228	$	271	$	16		$	24		$	5,020		$	4,976		$	228	$	271	$	18		$	21
Interest cost	7,088			7,226			571		582		130			157			7,093			7,064			571		581		125			88
Expected return on plan assets	(11,942		)	(11,687		)	—		—		(116		)	(111		)	(11,945		)	(11,589		)	—		—		(115		)	(112		)
Amortization of prior service cost	(495		)	(495		)	11		11		—			—			(495		)	(495		)	11		11		—			—
Amortization of net loss (gain)	—			—			269		228		(88		)	(29		)	—			—			269		228		(101		)	(233		)
Net periodic benefit cost	$	(326	)	$	(351	)	$	1,079	$	1,092	$	(58	)	$	41		$	(327	)	$	(44	)	$	1,079	$	1,091	$	(73	)	$	(236	)



Effective Date	Average Percentage Increase (Decrease) in Rates	Increase (Decrease) in Revenue (Dollars in Millions)¹
Electric:
May 1, 2017	2.0%	$41.9
May 1, 2016	1.0	20.8
Natural Gas:
May 1, 2017	2.4%	$22.4
May 1, 2016	2.8	25.4


¹	The increase in revenue is net of reductions from excess earnings of ~~$11.4~~$11.9 million for electric and ~~$2.1~~$2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.