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1	At December 31, 2017 and 2016, approximately 398,518 and 392,806 customers purchased both electricity and natural gas from PSE, respectively.

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

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2	National Oceanic and Atmospheric Administration (NOAA).

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

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

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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.

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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.

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

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•	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.

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•	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.

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•	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.

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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 changed to 9.5% effective December 19, 2017, per the approved GRC.

*	Not meaningful and/or applicable.

•	Regulated equity (rate base time's equity percent) was $478.0 million lower than AMA equity for the year ended December 31, 2017. The variance was primarily driven by the impact on rate base of the deferred tax liability for utility, plant and equipment. The impact on ROE for this variance was negative 1.2%.

•	Rates are based on an assumption of normal weather. The amount of variance due to weather was $13.2 million, which resulted in an impact on ROE of positive 0.3%.

•	Depreciation expense was $24.8 million higher than the amount allowed in rates for the year ended December 31, 2017 for an impact on ROE of negative 0.7%.

•	Partially offsetting the above was net revenue from below the line activities and interest savings which totaled $28.2 million for an impact on ROE of positive 0.7%.

•	Regulated equity (rate base time's equity percent) was $360.0 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. The impact on ROE for this variance was negative 1.0%.

•	Depreciation expense was $10.5 million higher than the amount allowed in rates for the year ended December 31, 2016.

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

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•	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;

•	Tax reform, the effect of lower tax rates, and regulatory treatment of excess deferred tax balances on rate 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.

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1	The increase in revenue is net of reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas effective May1, 2017, and $11.9 million for electric and $5.5 million for natural gas effective May 1, 2016.

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•	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. Inclusion of these costs in the decoupling mechanism was subsequently approved in the GRC. 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 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.

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•

Electric retail sales increased $112.5 million due an increase of $100.0 million from additional retail electricity usage of 4.2% compared to the prior year and an increase in rates of $12.5 million due to the decoupling rate mechanism. The additional usage was due to an increase of residential and commercial use per customer of 6.7% and 2.2%, respectively, an increase in heating degree days of 19.9% compared to 2016, and an increase in retail customers of 1.4%.

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•

Decoupling revenue decreased $20.0 million due to a decrease in decoupling deferrals of $23.5 million driven by actual revenue being closer to PSE's allowed revenue per the decoupling mechanism compared to 2016. The increase in actual revenue was due to an increase in load as discussed above in electric retail sales. This was partially offset by an increase in decoupling revenue of $3.5 million due to fixed production cost deferrals, which were removed from the PCA mechanism and placed into the decoupling mechanism effective January 1, 2017.

•

Other decoupling revenue decreased $6.5 million due to an increase in decoupling collections of $9.5 million due to an increase in rates in 2017. In 2016, there was $1.3 million of decoupling deferred revenue that could not be collected within 24 months compared to no reserve in the current year. The decoupling collection and refund of rate of return (ROR) excess earnings are driven by the tariff rates and retail sales.

•

Transportation and other revenue increased $92.5 million primarily due to a change in production tax credit (PTC) deferral revenue of $73.2 million due to a $19.9 million reduction to revenue in 2016 as PTCs were generated compared to no PTC generated in 2017, as well as, a $51.2 million remeasurement of the PTC deferral in 2017 due to tax law change. Additionally, there was an increase in net wholesale natural gas sales of $17.5 million due to increased purchased electricity, as discussed below.

•

Purchased electricity expense increased $58.4 million primarily due to an 11.2% increase in wholesale electricity purchases, partially offset by a 0.2% decrease in prices. The increase in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, a decrease of hydro and wind production of 7.4% and 14.7%, increased the need to purchase additional wholesale power.

•

Electric generation fuel expense decreased $9.1 million primarily due to a $2.7 million reduction in combustion turbine generation costs as a result of a 7.9% reduction in combustion turbine generation due to favorable wholesale electricity prices and a $6.3 million decrease in coal generation costs primarily at Colstrip units 3 and 4 for variable fuel costs due to less coal delivered and burned in 2017.

•

Residential exchange credits increased $6.1 million resulting from higher Residential Exchange Program (REP) credits associated with the BPA REP settlement due to the REP credit tariff increase in 2017 and increased usage. 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 BPA.  Pursuant to agreements (including settlement agreements) between BPA and PSE, BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

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

•

Electric retail sales increased $81.1 million due to increases in rates of $86.4 million primarily from the reduction of the residential exchange credits and an increase in the decoupling rate mechanism. The increase from rates was partially offset by $5.6 million due to a 0.3% reduction in retail electricity usage. The reduction in usage was due to a decrease of residential, commercial and industrial average use per customer of 0.6%, 2.7% and 2.5%, respectively, as a result of energy efficiency. The reduction in use per customer were offset by an increase in retail customers of 1.5% and an increase in heating degree days of 0.6% compared to 2015.

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•

Decoupling revenue increased $16.3 million due to actual revenues were lower than PSE's allowed revenue per the decoupling mechanism compared to 2015. This increase was primarily from residential and commercial decoupled rate schedules, which increased $15.6 million in 2016. The increase was driven from an increase in customers which increases the allowed revenue and a decrease in use per customer, which lowers the actual revenue resulting in higher decoupled revenue.

•

Other decoupling revenue decreased $4.5 million due to an increase of $16.8 million of decoupling collections as compared to 2015 from an increase in rates in 2016; partially offset by a decrease in the ROR excess earnings sharing of $13.5 million from a reduction in the ROR excess earnings accrual of $6.5 million compared to 2015 and an increase of $7.0 million in refunds to customers for the 2015 ROR excess earnings set into customer rates in 2016. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and retail sales.

•	Transportation and other revenue increased $13.6 million primarily due to a reduction of amortization of PTC deferral credits of $10.1 million since PTC generation at Hopkins Ridge ended in 2015 and increase in net wholesale natural gas sales of $6.8 million.

•

Purchased electricity expense increased $32.1 million primarily due to a 16.1% increase in wholesale electricity purchases, partially offset by a 8.3% decrease in wholesale electricity prices. The increase in purchases was primarily driven by an increase in load and lower wholesale electricity prices on the open market compared to generating power. Additionally, an increase of hydro and wind production of 32.2% and 14.4% decreased the need to purchase additional wholesale power due to favorable conditions.

•

Electric generation fuel expense decreased $34.6 million primarily due to a $43.0 million reduction in combustion turbine costs as a result of a 28.8% reduction in combustion turbine generation due to favorable wholesale electricity prices and increased wind and hydro generation. This was partially offset by an $8.4 million increase in coal generation costs primarily due to an increase in the weighted-average cost of coal.

•

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 BPA.  Pursuant to agreements (including settlement agreements) between BPA and PSE, BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

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•

Natural gas retail sales increased $148.1 million due to an increase of $155.1 million in natural gas sales, which is a result of an increase in natural gas load of 18.0% from 2016, partially offset by a decrease in revenue per therm of $6.9 million. The decrease in revenue per therm was primarily due to a rate decrease on customer bills for PGA, which decreased rates 0.4% effective November 1, 2016 and increase in decoupling rates of 2.4% effective May 1, 2017, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for natural gas rate changes. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 17.4% and 18.9%, respectively, compared to 2016 as a result of a 19.9% increase in heating degree days and an increase of 1.5% in natural gas customers, which increased the natural gas heating load compared to prior year.

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•	Decoupling revenue decreased $48.6 million primarily due to an increase in use per customer, driven by an increase in heating degree days as discussed above in natural gas retail sales. This caused actual revenue to increase closer to PSE's allowed revenue, which lowered decoupled revenue in 2017.

•

Other decoupling revenue increased $5.9 million due to the following: (i) an increase in decoupling collections of $14.7 million from an increase in the amortization rate in 2017 and an increase in therms used; (ii) in 2017, there was $19.6 million of deferred decoupling revenue that was recognized as it met the alternative revenue program revenue recognition criteria that it is expected to be collected from customers within 24 months, compared to the 24-month reserve of $9.6 million in 2016; and (iii) an increase in net overearnings accruals and cash refunds of $8.6 million.

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

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•

Natural gas retail sales revenue decreased $53.7 million due to a decrease in revenue per therm of $90.6 million, partially offset by an increase of $41.0 million in natural gas sales, due to an increase in natural gas load of 4.6% from 2015. The decrease in revenue per therm was primarily due to a rate decrease on customer bills for PGA, which decreased rates 17.4% effective November 1, 2015 partially offset by an increase in decoupling rates of 2.8% effective May 1, 2016, see Management's Discussion and Analysis, "Regulation and Rates" included in Item 7 of this report for natural gas rate changes. Natural gas load increased primarily due to the increase in average therms used per residential and commercial customers of 4.0% and 0.7%, respectively, compared to 2015. In addition, natural gas customers increased by 1.6% and heating degree days increased by 0.6%, which increased the natural gas heating load compared to prior year.

•

Other decoupling revenue decreased $2.7 million due to an increase in decoupling deferral collection of $17.9 million, as a result of an additional $17.3 million being set in rates on May 1, 2016, which was partially offset by a decrease in ROR excess earnings sharing accrual of $12.5 million and an increase in ROR excess earnings refund in 2016 of $2.5 million. The decoupling collection and refund of ROR excess earnings are driven by the tariff rates and customer usage.

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•

Net unrealized (gain) loss on derivative instruments expense increased $114.6 million to a net loss of $30.8 million for the year ended December 31, 2017. The primary drivers for the increase consist of a reduction of $20.6 million in gains from contract settlements previously recorded as losses that settled to purchased electricity or electric generation fuel and a $94.0 million loss due to a decrease in natural gas and electricity forward prices of 26.9% and 27.5%, respectively. The $20.6 million reduction from contract settlements was comprised of a $16.5 million from natural gas and a $4.1 million from wholesale electric contracts. The decrease in the weighted average natural gas and wholesale electric forward prices resulted in a $78.4 million loss and a $15.6 million loss, respectively.

•

Utility operations and maintenance expense increased $15.8 million primarily driven by increases in the following: $6.7 million for electric and natural gas operations primarily due to increased electric operations third-party service provider costs of $3.2 million and gas distribution system integrity costs of $2.0 million $5.5 million increase in outside services expense for customer service optimization initiatives that began in 2016, and a $4.6 million increase in overall labor expense. These increases were partially offset by $1.6 million reduction of uncollectible account costs compared to 2016.

•	Non-utility and other expense increased $14.5 million primarily due to an increase in the long-term incentive plan of $12.3 million in 2017 which resulted from a total return in 2017 of 29.1% which resulted in the total return component to be funded at 200.0%. For more information see Part III, "Executive Compensation" included in Item 11 of this report for the Company's long term incentive plan.

•

Depreciation and amortization expense increased $55.8 million primarily due to the following: (i) electric depreciation expense of $12.1 million, primarily due to asset net additions to distribution, transmission, and general plant of $186.4 million, $92.0 million and $83.1 million respectively; (ii) natural gas depreciation expense of $6.1 million increased due primarily to net additions to distribution assets of $192.3 million; (iii) $15.5 million of amortization expense due to

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•	Taxes other than income taxes increased $32.0 million primarily due to increases in municipal taxes of $11.5 million and state excise taxes of $10.2 million as a result of an increase in revenue and an increase of $9.3 million in property taxes related to increased property values and expected levy rates.

•	Income tax expense increased $36.6 million primarily driven by the impact of tax reform on the deferred tax balances and partially offset by a 4.3% decrease in pre-tax income. For additional information, see Note 13, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.

•

Net unrealized (gain) loss on derivative instruments expense decreased $71.1 million to a net gain of $83.8 million for the year ended December 31, 2016. The primary drivers for the 2016 net gain consist of a $61.7 million gain from contract settlements previously recorded as losses in the 2015 unrealized gain on derivative instruments that settle to purchased electricity and electric generation fuel. The $61.7 million gain from contract settlements was comprised of a $39.7 million gain from natural gas and a $22.0 million gain from wholesale electric contract settlements. Natural gas and wholesale electricity gain increased $22.1 million primarily due to increases in forward market prices of 5.7% and 10.8%, respectively. This compares to a net gain of $12.7 million in 2015, comprised of $83.6 million in settlement gains offset by a $70.9 million loss due to a decrease in natural gas and wholesale electricity prices.

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•

Utility operations and maintenance expense increased $37.8 million primarily driven by (i) an increase of $26.9 million of maintenance expense primarily related to natural gas leak repairs and sewer cross bore inspections, maintenance on gearboxes and generators at the Hopkins Ridge and Wild Horse wind generation facilities, electric distribution maintenance for overhead lines and vegetation management; (ii) an increase of outside services expense of $7.4 million primarily related to customer service initiatives; (iii) an increase of salary expense of $2.9 million primarily related to incentive increases; partially offset by (iv) a decrease of $4.6 million in meter reading expense due to the purchase of previously leased meter reading equipment during 2015.

•	Depreciation and amortization expense increased $15.7 million primarily due to $16.5 million of depreciation expense primarily due to net additions of $173.9 million of natural gas distribution assets, $148.5 million of electric distribution assets and $90.6 million of electric transmission assets.

•

Taxes other than income taxes increased $8.1 million primarily due to an increase in electric property taxes of $6.0 million based on assessed value and levy rates, electric state excise and municipal taxes of $5.8 million driven by an increase in electric revenue, partially offset by a decrease of $4.8 million in natural gas state excise and municipal taxes from a decrease in natural gas revenue.

•

Interest expense decreased $6.3 million primarily due to a reduction of $3.8 million in interest on long-term debt related to debt that was refinanced in May 2015 at an interest rate of 4.30% compared to interest rates of 5.197% and 6.75%; and an increase of $1.7 million related to allowance for funds used during construction (AFUDC) debt due to an increase in average construction work in progress (CWIP).

•

Income tax expense increased $49.4 million primarily driven by $44.0 million from higher pre-tax income and an increase of $6.5 million due to Hopkins Ridge no longer generating PTCs. PTCs are generated for the first ten years at a wind facility. As of December 2015, Hopkins Ridge is no longer eligible to generate PTCs. For additional information, see Note 13, "Income Taxes" to the consolidated financial statements included in Item 8 of this report.

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•	Income Tax Expense increased by $79.3 million primarily due to tax reform passed on December 22, 2017 that lowered the corporate tax rate from 35.0% to 21.0%. As a result, income tax expense was effected by the revaluation of Puget Energy's deferred tax assets at the 21.0% rate.

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

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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

As of December 31, 2017, 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 2022. 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, 2017, no loans or letters of credit were outstanding under the credit facility and $329.5 million was outstanding under the commercial paper program. The credit agreement is syndicated among numerous lenders. Outside of the credit agreement, PSE has a $3.1 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

2	As of December 31, 2017, 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, 2017, Puget Energy had a revolving senior secured credit facility totaling $800.0 million, which matures in October 2022. 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, 2017, there was $102.6 million drawn and outstanding under the Puget Energy credit facility.

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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.

•

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

•

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

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

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

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

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

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

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

•	Changes in cash flow resulting from working capital decreased $33.2 million primarily due to amounts owed to PSE related to Puget LNG.

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•	Approximately $2.6 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $4.3 billion of electric bondable property available for issuance, subject to 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, 2017; and

•

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

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

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•	Our Board has adopted clear corporate governance guidelines.

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

•	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.

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

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

•	The Company has adopted a Corporate Ethics and Compliance Code 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.

•	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.

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

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

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

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1	Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

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1	New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.

•	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.

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*	Not Applicable.

1	6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017.

2	5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.

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

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

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

4	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the 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 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016.

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1	All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off.

2	Interest Rate Swap Contracts are only held at Puget Energy and matured in January 2017.

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1	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 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.

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

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

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

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1	The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

2	The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

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

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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.

2	The Company had no purchases, sales or issuances during the reported periods.

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

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•	For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay.

•	For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck.

•	401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed. An employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested.

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•

Company Contribution: New UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 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 and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4.0% contribution will vest after three years of service.

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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 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 primarily consist of common/collective trust funds and two partnerships held as of December 31, 2017.

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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, 2017.

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 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 a common/collective trust fund as of December 31, 2017.

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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.

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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.

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(a)	These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

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(a)	These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

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1	Eliminated in consolidation.

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•	Kimberly J. Harris, President and Chief Executive Officer (CEO);

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•

Design and deliver a competitive total compensation opportunity.  To attract, retain and motivate a talented executive team, the Committee believes that total pay opportunity should be competitive with companies of similar size and scope of operations so that new executives will want to join the Company and current executives will be retained.  As described below in the discussion of Compensation Program Elements (Review of Pay Element Competitiveness), the Committee 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 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. The Committee also recognizes the importance of providing retirement income.  Executives choose to work for 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 retirement programs provided by our comparator group and provides benefits that are commensurate with this group.

•

Place a significant portion of each executive’s target total 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 an incentive compensation program that supports the Company’s business strategy as approved by the Board 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 earned based on achievement relative to annual and long-term performance goals.  By establishing goals, monitoring results, and rewarding achievement of goals, the Company focuses executives on actions that will improve the Company and enhance investor value, while also retaining key talent.  The Committee annually evaluates the performance factors 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 program 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.

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•	Customer Satisfaction (3 SQIs) - Customer satisfaction with the telephone access center and natural gas field services and number of Washington Commission complaints.

•	Safety and Reliability (4 SQIs) - Gas emergency response, electric emergency response, non-storm outage frequency and non-storm outage duration.

•	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 0.52 in 2017.

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•	All employees complete an online defensive driving training. The target completion rate is no less than 95%.

*	Combined SQI & Safety results of 6/10 or better and minimum EBITDA of $1,156 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%).

•	Safety - Our Safety Objective is our foundation: If Nobody Gets Hurt Today, we will feel safe and secure and be able to perform at our best.

•	People - When we’re Safe, we can achieve our People Objective of being a Great Place to 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 and Tools Objective where results start with achieving 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 of delivering greater value and being our Customer’s Energy Partner of Choice in a competitive marketplace.

•	Financial - Being our customer’s energy partner of choice takes us to our Financial Objective of increasing our Financial Strength, allowing us to sustain further improvement.

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•	Performance on Total Return in 2017 was 29.1%, which was significantly higher than target, reflecting an increase in valuation due to market transactions during 2017.

•	Performance on the Total Return component for the three-year performance cycle was a compounded annual rate of 14.93%, above target and at the maximum of the funding scale. The Total Return Component funded at 200% of target units.

•	Performance on the ROE component of the grant was an average of 102.2% of target for funding at 112.8% of target units.

1	Target LTI Plan incentive is a percentage of 2015 base salary when the grants were made in 2015.

2	2015-2017 actual LTI Plan amount payable is equal to the unit price $67.61 multiplied by earned Total Return and ROE component units.

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1

For 2017, reflects individual performance above target as described in the "Compensation Discussion and Analysis," section titled "2017 Annual Incentive Plan Results" in the amount of: Ms. Harris, $50,940. For 2016, also included additional incentive paid based on review of 2015 results for SQIs 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 in the amount of: Ms. Harris, $183,600; Mr. Secrist, $35,648; Ms. Mellies, $7,085.

2

For 2017, reflects annual cash incentive compensation paid under the 2017 Goals and Incentive Plan and cash incentive compensation paid under the LTI Plan for the 2015-2017 performance cycle. Cash incentive amounts were paid in early 2018 or deferred at the executive's election.  The 2017 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 2018.

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 2017, updated interest rates and mortality assumptions have generally increased the actuarial value of the underlying retirement benefits relative to assumptions for 2016.  Information regarding these pension plans is set forth in further detail under “2017 Pension Benefits.”  The change in pension value amounts for 2017 are: Ms. Harris, $1,520,618; Mr. Doyle, $483,109; Mr. Secrist, $576,802, Ms. Mellies, $478,462; and Mr. Bussey, $465,653.  Also included in this column are the portions of Deferred Compensation Plan earnings that are considered above market.  These amounts for 2017 are: Ms. Harris, $3,165; Mr. Doyle, $0; Mr. Secrist, $0; Ms. Mellies, $443; and Mr. Bussey, $0. See the “2017 Nonqualified Deferred Compensation” table for all Deferred Compensation Plan earnings.

4	All Other Compensation for 2017 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 and retired effective January 8, 2018.

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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.

2

Includes Company contributions during 2017 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, $18,850; Mr. Secrist $18,850 ; Ms. Mellies, $18,850; and Mr. Bussey, $18,850 Company contributions to the Deferred Compensation Plan are as follows: Ms. Harris, $0; Mr. Doyle, $29,666; Mr. Secrist, $21,566; Ms. Mellies, $11,131; and Mr. Bussey, $0.

3	Reflects the value of imputed income for life insurance and Company paid premiums on supplemental disability insurance.

1

As described in the “Compensation Discussion and Analysis,” the 2017 Goals and Incentive Plan had dual funding triggers in 2017 of $1,156 million EBITDA and SQI performance of 6/10.  Payment would be $0 if either trigger is not met.  The threshold estimate assumes $1,156 million EBITDA and SQI/Safety measure performance at 6/10. The target estimate assumes $1,284.4 million EBITDA and SQI/Safety measure performance at 10/10.  The maximum estimate assumes $1,733.9 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 2017-2019 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.

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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, 2017 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 4.00%, and the post-retirement mortality assumption is based on the 2018 417(e) unisex mortality table. Annuity benefits are converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.75%, 3.76%, and 4.66% (the 24-month average of the underlying rates as of September 2017).  These assumptions are consistent with the ones used for the Retirement Plan and the SERP for financial reporting purposes for 2017.  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, 2016 for the benefits earned as of that date using the assumptions used for financial reporting purposes for 2016.  These assumptions included assumed cash balance interest credits of 4.0%, a discount assumption of 4.50% and post-retirement mortality assumption based on the 2017 417(e) unisex mortality table. Annuity benefits were converted to lump sum amounts at retirement based on assumed future 417(e) segment rates of 1.52%, 3.80% and 4.79% (the 24-month average of the underlying rates as of September 2016). Other assumptions used to determine the value as of December 31, 2016 were the same as those used for December 31, 2017.

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, 2017.  Each SERP-eligible Named Executive Officer was vested in his or her SERP benefits as of December 31, 2017.

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1

The amount in this column reflects elective deferrals by the executive of salary, annual incentive compensation or LTI Plan awards paid in 2017.  Deferred salary amounts are: Ms. Harris, $0; Mr. Doyle, $27,866; Mr. Secrist, $32,355; Ms. Mellies, $10,706; 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. The amounts are also included in the applicable column of the Summary Compensation Table for 2017.

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

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

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

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•	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 2017, no amount is shown in the table below;

•

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

•

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

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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, 2017. These values are based on interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements.

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

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

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

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

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

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

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

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

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

•	Independent Board Chairman, $13,750;

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

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

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

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

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1

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

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

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

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

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

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

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

2

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

3

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.

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

•

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

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

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

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

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

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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 2017 fees are estimated and include an aggregate amount of $1.7 million billed to Puget Energy and $1.6 million to PSE through December 2017.

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.

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a)	Documents filed as part of this report:

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*	Filed herewith.

**	Management contract, compensatory plan or arrangement.

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