REGULATORY MATTERS

Regulatory Assets and Liabilities

The following table presents the Company’s regulatory assets and liabilities as of December 31, 2016 (dollars in thousands):



			Receiving Regulatory Treatment
	Remaining Amortization Period		(1) Earning A Return		Not Earning A Return		(2) Expected Recovery or Refund		Total 2016		Total 2015
Regulatory Assets:
Investment in exchange power-net	2019		$	6,533	$	—	$	—	$	6,533	$	8,983
Regulatory assets for deferred income tax	(3	)	101,372		8,481		—		109,853		101,240
Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		240,114		—		240,114		235,009
Current regulatory asset for energy commodity derivatives	(5	)	—		11,365		—		11,365		17,260
Unamortized debt repurchase costs	(6	)	13,700		—		—		13,700		15,520
Regulatory asset for settlement with Coeur d’Alene Tribe	2059		45,265		—		—		45,265		46,576
Demand side management programs	(3	)	—		15,700		—		15,700		3,168
Deferred maintenance costs	2018		—		2,672		—		2,672		4,823
Decoupling surcharge	2018		43,126		—		—		43,126		13,312
Regulatory asset for utility plant to be abandoned	(7	)	19,100		—		—		19,100		—
Regulatory asset for interest rate swaps	(8	)	37,912		—		123,596		161,508		83,973
Non-current regulatory asset for energy commodity derivatives	(5	)	—		16,919		—		16,919		32,420
Other regulatory assets	(3	)	3,633		5,755		4,585		13,973		17,348
Total regulatory assets			$	270,641	$	301,006	$	128,181	$	699,828	$	579,632
Regulatory Liabilities:
Natural gas deferrals	(3	)	$	30,820	$	—	$	—	$	30,820	$	17,880
Power deferrals	(3	)	23,528		—		—		23,528		18,747
Regulatory liability for utility plant retirement costs	(9	)	273,983		—		—		273,983		261,594
Income tax related liabilities	(3	)	—		28,966		—		28,966		17,609
Regulatory liability for interest rate swaps	(8	)	12,442		—		8,749		21,191		23
Provision for earnings sharing rebate	(3	)	—		3,697		6,600		10,297		12,237
Decoupling rebate	2017		2,405		—		—		2,405		2,373
Other regulatory liabilities	(3	)	2,505		3,257		—		5,762		3,420
Total regulatory liabilities			$	345,683	$	35,920	$	15,349	$	396,952	$	333,883


(1)	Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return.


(2)	Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence.


(3)	Remaining amortization period varies depending on timing of underlying transactions.


(4)	As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency.

(5)

The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

(6)

For the Company’s Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are included in the Company's cost of debt calculation for ratemaking purposes and are recovered through retail rates.

(7)

In March 2016, the UTC granted the Company's Petition for an Accounting Order to defer and include in a regulatory asset the undepreciated value of its existing Washington electric meters for the opportunity for later recovery. This accounting treatment is related to the Company's plan to replace approximately 253,000 of its existing electric meters with new two-way digital meters and the related software and support services through its AMI project in Washington State. Replacement of the meters is expected to begin in the second half of 2017. For ratemaking purposes, the existing electric meters won't be recorded as regulatory assets until they are physically removed from service, but for GAAP purposes, they are regulatory assets upon the commitment by management to retire the meters.

(8)

For interest rate swap derivatives, each period Avista Utilities records all mark-to-market gains and losses in each accounting period as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt and are also included as a part of the Company's cost of debt calculation for ratemaking purposes. See Note 14 regarding a reclassification of settled interest rate swap derivatives during 2016. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery.


(9)	This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant.

Power Cost Deferrals and Recovery Mechanisms

Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future prudence review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:


•	short-term wholesale market prices and sales and purchase volumes,


•	the level and availability of hydroelectric generation,


•	the level and availability of thermal generation (including changes in fuel prices), and


•	retail loads.

In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. The Washington ERM calculation is subject to certain deadbands and sharing bands. For 2016, the Company recognized a pre-tax benefit of $5.1 million under the ERM in Washington compared to a benefit of $6.3 million for 2015. Total net deferred power costs under the ERM were a liability of $21.3 million as of December 31, 2016 compared to a liability of $18.0 million as of December 31, 2015, and these deferred power cost balances represent amounts due to customers.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a liability of $2.2 million as of December 31, 2016 compared to an asset of $0.2 million as of December 31, 2015.

Natural Gas Cost Deferrals and Recovery Mechanisms

Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $30.8 million as of December 31, 2016 compared to a liability of $17.9 million as of December 31, 2015.

Decoupling and Earnings Sharing Mechanisms

Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, each month Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes, rather than KWh and therm sales. The difference between revenues based on the number of customers and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year.

Washington Decoupling and Earnings Sharing

In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period beginning January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments.

The electric and natural gas decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms

In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, beginning January 1, 2016.

For the period 2013 through 2015 the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if the Company's ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 Idaho electric and natural gas general rates cases. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

Oregon Decoupling Mechanism

In February 2016, the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and Idaho mechanisms described above. The decoupling mechanism became effective on March 1, 2016 and there will be an opportunity for interested parties to review the mechanism and recommend changes, if any, by September 2019. An earnings review is conducted on an annual basis, which is filed by the Company with the OPUC on or before June 1 of each year for the prior calendar year. In the annual earnings review, if the Company earns more than 100 basis points above its allowed return on equity, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.

Cumulative Decoupling and Earnings Sharing Mechanism Balances

As of December 31, 2016 and December 31, 2015, the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands):



	December 31,			December 31,
	2016			2015
Washington
Decoupling surcharge	$	30,408		$	10,933
Provision for earnings sharing rebate	(5,113		)	(3,422		)
Idaho
Decoupling surcharge	$	8,292		n/a
Provision for earnings sharing rebate	(5,184		)	(8,814		)
Oregon
Decoupling surcharge	$	2,021		n/a
Provision for earnings sharing rebate	—			—

(n/a) This mechanism did not exist during this time period.