
Puget Sound Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)				2019			2018
Storm damage costs electric	1 to 4 years	$	121,894		$	118,331
Chelan PUD contract initiation	11.8 years	83,875			90,964
Environmental remediation	(a)	68,486			76,345
Lower Snake River	17.4 years	62,899			67,021
Decoupling deferrals and interest	Less than 2 years	43,509			65,779
Baker Dam licensing operating and maintenance costs	N/A	56,427			55,607
Deferred Washington Commission AFUDC	30 years	57,553			52,029
Property tax tracker	Less than 2 years	22,442			45,621
Unamortized loss on reacquired debt	2 to 48 years	40,177			42,378
Colstrip 1 & 2 Regulatory Asset	N/A	—			37,674
Energy conservation costs	(a)	25,272			30,701
Get to zero depreciation expense deferral	N/A	22,148			—
Advanced metering infrastructure	(a)	14,845			—
Generation plant major maintenance, excluding Colstrip	3 to 10 years	12,744			15,027
PGA deferral of unrealized losses on derivative instruments	N/A	—			14,739
White River relicensing and other costs	1 year	6,399			12,966
Mint Farm ownership and operating costs	5.3 years	10,318			12,319
PGA receivable	2 years	132,766			9,922
Snoqualmie licensing operating and maintenance costs	N/A	7,442			7,407
Colstrip major maintenance	0.0 years	2,929			6,841
PCA mechanism	N/A	41,745			4,735
Colstrip common property	4.4 years	3,188			3,903
Ferndale	0.0 years	—			3,316
Various other regulatory assets	(a)	10,474			14,583
Total PSE regulatory assets		$	847,532		$	788,208
Deferred income taxes (d)	N/A	(946,936)			(976,582)
Cost of removal	(b)	(469,922)			(424,727)
Treasury grants	18 years	(101,981)			(168,884)
Production tax credits	(c)	(85,323)			(93,616)
Gain on Sale Shuffleton	N/A	(12,483)			—
Microsoft special contract regulatory liability	N/A	(12,661)			—
Repurposed production tax credits	N/A	(23,171)			—
Accumulated provision for rate refunds	N/A	—			(34,579)


Total decoupling liability	Less than 2 years	(8,500)			(13,758)

Various other regulatory liabilities	(a)	(15,573)			(10,316)
Total PSE regulatory liabilities		(1,676,550)			(1,722,462)
PSE net regulatory assets (liabilities)		$	(829,018)		$	(934,254)


Puget Energy	Remaining Amortization Period	December 31,
(Dollars in Thousands)		2019		2018
Total PSE regulatory assets	(a)	$	847,532	$	788,208
Puget Energy acquisition adjustments:
Regulatory assets related to power contracts	6 to 33 years	14,146		16,693

Total Puget Energy regulatory assets		861,678		804,901
Total PSE regulatory liabilities	(a)	(1,676,550)		(1,722,462)
Puget Energy acquisition adjustments:
Deferred income taxes		757		608
Regulatory liabilities related to power contracts	6 to 33 years	(156,597)		(162,711)
Various other regulatory liabilities	Varies	(1,265)		(1,323)
Total Puget Energy regulatory liabilities		(1,833,655)		(1,885,888)
Puget Energy net regulatory asset (liabilities)		$	(971,977)	$	(1,080,987)

PSE filed a GRC with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in our original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase.

In January 2017, PSE filed its GRC with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017, and new rates became effective December 19, 2017. The settlement agreement provided for a weighted cost of capital of 7.6%, or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%, annually.

On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase.

On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes.

The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019:

The agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in the test year of the filing. The agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s 2019 GRC. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49% . On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE must pass back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which began May 1, 2019.

The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4%, for electric and $23.6 million, or 2.7%, for natural gas and became effective May 1, 2018, by operation of law.

The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers.

As a result of the Washington Commission's final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2019, through February 28, 2019, was addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019.

While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since July 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs 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 are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period.

On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case (PCORC). Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended.

On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019.

On December 31, 2019, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2019 decoupling revenue. The previously unrecognized decoupling deferrals of $0.8 million and $20.8 million at December 31, 2018, and December 31, 2016, were recognized as decoupling revenue in the year ended December 31, 2019, and December 31, 2017, respectively.

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.

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

For the year ended December 31, 2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to customers and $1.0 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $3.5 million for the year ended December 31, 2018, of which no amounts were apportioned to customers and accrued $0.2 million of interest on the total deferred customer balance. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a narrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a transmission line, which contributed to a liquidity crisis at Mid-C and resulted in high market power prices; and (iv) The relative prices of natural gas and power, which reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices.

For the year ended December 31, 2018, PSE had a beginning PGA payable balance of $16.1 million, incurred actual natural gas costs of $319.3 million, of which $292.0 million was recovered through rates. The difference between actual and allowed costs, less interest $1.3 million, resulted in a PGA receivable of $9.9 million. For the year ended December 31, 2019, PSE had incurred actual natural gas costs of $406.2 million, of which $289.9 million was recovered through rates. The difference between actual and allowed costs, plus interest of $6.6 million, resulted in a PGA receivable of $132.8 million.

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

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

On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, 2019, PSE deferred $21.7 million of depreciation expense for GTZ. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. For the year ended December 31, 2019, PSE deferred $0.5 million of carrying charges on the deferral. The GTZ accounting petition was consolidated with

The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2019, PSE incurred $39.3 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $0.4 million and $28.5 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $25.4 million incurred in storm-related electric transmission and distribution system restoration costs for the year ended December 31, 2018, of which the Company deferred $3.3 million and $11.9 million as regulatory assets related to storms that occurred in 2017 and 2018, respectively. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold.

The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $41.8 million for natural gas and $8.7 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, 2019, the Company’s share of future remediation costs is estimated to be approximately $31.6 million. The Company's deferred electric environmental costs are $13.7 million and $14.1 million at December 31, 2019 and 2018, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $54.8 million and $62.2 million at December 31, 2019 and 2018, respectively, net of insurance proceeds. In the 2017 GRC, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates, effective December 19, 2017.