AVISTA UTILITIES REGULATORY MATTERS

Regulatory Assets and Liabilities

The following table presents the Company’s regulatory assets and liabilities as of December 31, 2013 (dollars in thousands):



			Receiving Regulatory Treatment
	Remaining Amortization Period		(1) Earning A Return		Not Earning A Return		(2) Expected Recovery		Total 2013		Total 2012
Regulatory Assets:
Investment in exchange power-net	2019		$	13,883	$	—	$	—	$	13,883	$	16,333
Regulatory assets for deferred income tax	(3	)	71,421		—		—		71,421		79,406
Regulatory assets for pensions and other postretirement benefit plans	(4	)	—		156,984		—		156,984		306,408
Current regulatory asset for utility derivatives	(5	)	—		10,829		—		10,829		35,082
Unamortized debt repurchase costs	(6	)	19,417		—		—		19,417		21,635
Regulatory asset for settlement with Coeur d’Alene Tribe	2059		49,198		—		—		49,198		50,509
Demand side management programs	(3	)	—		9,576		—		9,576		2,579
Montana lease payments	(3	)	3,022		—		—		3,022		4,059
Lancaster Plant 2010 net costs	2015		2,607		—		—		2,607		3,967
Deferred maintenance costs	2016		—		5,813		—		5,813		6,312
Power deferrals	(3	)	5,065		—		—		5,065		—
Regulatory asset for interest rate swaps	2013		—		—		—		—		1,406
Non-current regulatory asset for utility derivatives	(5	)	—		23,258		—		23,258		25,218
Other regulatory assets	(3	)	4,002		4,683		4,597		13,282		13,717
Total regulatory assets			$	168,615	$	211,143	$	4,597	$	384,355	$	566,631
Regulatory Liabilities:
Natural gas deferrals	(3	)	$	12,075	$	—	$	—	$	12,075	$	6,917
Power deferrals	(3	)	17,904		—		—		17,904		27,323
Regulatory liability for utility plant retirement costs	(7	)	242,850		—		—		242,850		234,128
Income tax related liabilities	(3	)	—		9,203		—		9,203		17,206
Regulatory liability for interest rate swaps	2014-2015		—		33,543		—		33,543		7,265
Regulatory liability for Spokane Energy	(8	)	—		—		25,046		25,046		21,488
Other regulatory liabilities	(3	)	7,249		6,411		—		13,660		4,316
Total regulatory liabilities			$	280,078	$	49,157	$	25,046	$	354,281	$	318,643


(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 that have 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 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. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in 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 recovered through retail rates as a component of interest expense.


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


(8)	Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods.

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),


•	the net value from optimization activities related to the Company's generating resources, and


•	retail loads.

In Washington, the Energy Recovery Mechanism (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 the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of $17.9 million as of December 31, 2013, and these deferred power cost balances represent amounts due to customers. As part of the approved Washington general rate case settlement in December 2012, during 2013 a one-year credit designed to return to customers $4.4 million from the existing ERM deferral balance reduced the net average electric rate increase impact to customers in 2013. Additionally, during 2014 a one-year credit up to $9.0 million will be returned to electric customers from the ERM deferral balance, so the net average electric rate increase impact to customers effective January 1, 2014 was also be reduced. The credits to customers from the ERM balances do not impact the Company's net income.

Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. The Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. The Company shares annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent customers/50 percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, there is a 90 percent customers/10 percent Company share ratio of the cost variance.

The following is a summary of the ERM:



Annual Power Supply Cost Variability	Deferred for Future Surcharge or Rebate to Customers	Expense or Benefit to the Company
within +/- $0 to $4 million (deadband)	0%	100%
higher by $4 million to $10 million	50%	50%
lower by $4 million to $10 million	75%	25%
higher or lower by over $10 million	90%	10%

As part of the April 2012 Washington general rate case filing, the Company proposed modifications to the ERM deadband and other sharing bands. The proposed modifications were not agreed to as part of the settlement agreement, and the ERM continued unchanged. However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the previous 10 percent of base revenues (approximately $45 million) under the mechanism.

Avista Utilities has a Power Cost Adjustment (PCA) mechanism in Idaho that allows it to modify electric rates on October 1 of each year with Idaho Public Utilities Commission (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. These annual 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 regulatory asset of $5.1 million as of December 31, 2013 compared to a regulatory liability of $5.1 million as of December 31, 2012.

Natural Gas Cost Deferrals and Recovery Mechanisms

Avista Utilities files a purchased gas cost adjustment (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. These annual PGA filings in Washington and Idaho provide for the deferral, and recovery or refund, of 100 percent of the difference between actual and estimated commodity and pipeline transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or refund, of 100 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby Avista Utilities defers, and recovers or refunds, 90 percent of the difference between these actual and estimated costs. Total net deferred natural gas costs to be refunded to customers were a liability of $12.1 million as of December 31, 2013 compared to a liability of $6.9 million as of December 31, 2012.

Washington General Rate Cases

In December 2011, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May 2011. The settlement agreement provided that base electric rates for Washington customers increase by an average of 4.6 percent, which was designed to increase annual revenues by $20.0 million. Base natural gas rates for Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $3.8 million. The new electric and natural gas rates became effective on January 1, 2012.

In addition, the settlement agreement provided for the deferral of certain generation plant maintenance costs. For 2011 and 2012 the Company compared actual non-fuel maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline maintenance expenses used to establish base retail rates, and deferred the difference. This deferral occurred each year, with no carrying charge, with deferred costs to be amortized over a four-year period, beginning the year following the period costs are deferred. Total net deferred costs under this mechanism in Washington were a regulatory asset of $3.1 million as of December 31, 2013 compared to a regulatory asset of $4.0 million as of December 31, 2012. As part of the settlement agreement relating to the Company's latest general rate case approved in December 2012, the parties agreed to terminate the maintenance cost deferral mechanism on December 31, 2012, with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.

In December 2012, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013, provided that base rates for Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). Under the settlement, there was a one-year credit designed to return $4.4 million to electric customers from the existing ERM deferral balance so the net average electric rate increase impact to the Company's customers in 2013 was 2.0 percent. The credit to customers from the ERM balance did not impact the Company's earnings.

The approved settlement also provided that, effective January 1, 2014, the Company increased base rates for Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement provides for a one-year credit up to $9.0 million to electric customers from the ERM deferral balance, so the net average electric rate increase to customers effective January 1, 2014 was 2.0 percent. The credit to customers from the ERM balance will not impact the Company's earnings. The ERM balance as of December 31, 2013 was a liability of $17.9 million.

The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47.0 percent, resulting in an overall rate of return on rate base of 7.64 percent.

The December 2012 UTC Order approving the settlement agreement included certain conditions.


(1)	The new retail rates to become effective January 1, 2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any intervening action from the UTC. The original settlement agreement has a provision that the Company will not file a general rate case in Washington seeking new rates to take effect before January 1, 2015.

(2)

In its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that was contemplated in the settlement agreement, this could result in base rates which are considered too high by the UTC. Avista Corp. is required to file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. The Company expects total utility capital expenditures to be above the level contemplated in the settlement agreement.

On February 4, 2014 the Company filed electric and natural gas general rates cases with the UTC. The Company has requested an overall increase in base electric rates of 3.8 percent (designed to increase annual electric revenues by $18.2 million) and an overall increase in base natural gas rates of 8.1 percent (designed to increase annual natural gas revenues by $12.1 million). The requests are based on a proposed overall rate of return of 7.71 percent, with a common equity ratio of 49.0 percent and a 10.1 percent return on equity.

Avista Corp. has also proposed a rebate beginning January 1, 2015, related to its sale of renewable energy credits (REC), that would reduce customers' monthly electric bills by 1.1 percent. The rebate associated with the sale of RECs is in response to the UTC Order approving the Company's previous general rate case settlement in December 2012. This proposed REC rebate would commence simultaneously with the expiration of two rebates that, together, are currently reducing customers' monthly electric bills by 2.8 percent. The net effect, commencing January 1, 2015, of the proposed new 1.1 percent rebate and the expiration of the current 2.8 percent rebate would be an increase in monthly electric bills of approximately 1.7 percent from 2014 levels. These rebates do not increase or decrease Avista Corp.'s earnings.

The combination of the 3.8 percent requested increase in base electric rates and the effective 1.7 percent increase attributable to the rebates would be a 5.5 percent increase electric billings.

As part of the Company's electric and natural gas general rate case filings, it has requested the implementation of decoupling mechanisms which sever the link between actual volumetric sales and the recovery of the Company's fixed costs. Under the proposed decoupling mechanisms, the Company would compare actual non-power supply (electric) and non-PGA (natural gas) revenue to the allowed non-power supply and non-PGA revenue, as the case may be, and the difference would be deferred and either rebated or surcharged to customers, depending on the position of the deferral accounts, over a one-year period. The deferral balances would be reviewed annually by the UTC prior to the implementation of any annual rate adjustments under the mechanisms.

The proposed mechanisms would be subject to an annual earnings test which proposes that if the Company's actual annual “Commission-basis” rate of return exceeds the most recently authorized Commission-basis rate of return for the Company's Washington electric and natural gas operations, the amount of a proposed surcharge is reduced or eliminated to reduce the rate of return to the Commission-authorized level. In addition, the mechanisms would be subject to an annual rate increase limitation which would prevent the amount of the incremental proposed rate adjustments under the mechanisms from exceeding a 3 percent rate increase for each of electric and natural gas operations.

The UTC has up to 11 months to review the filings and issue a decision.

Idaho General Rate Cases

In September 2011, the IPUC approved a settlement agreement in the Company’s general rate case filed in July 2011. The new electric and natural gas rates became effective on October 1, 2011. The settlement agreement provided that base electric rates for the Company’s Idaho customers increase by an average of 1.1 percent, which was designed to increase annual revenues by $2.8 million. Base natural gas rates for the Company’s Idaho customers increased by an average of 1.6 percent, which was designed to increase annual revenues by $1.1 million.

The September 2011 settlement agreement provides for the deferral of certain generation plant operation and maintenance costs. In order to address the variability in year-to-year operation and maintenance costs, beginning in 2011, the Company is deferring certain changes in operation and maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4 of the Colstrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in the year following the period costs are deferred. The amount of expense to be requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this mechanism in Idaho were regulatory assets of $2.8 million as of December 31, 2013 and $2.3 million as of December 31, 2012.

In March 2013, the IPUC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for the Company's Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. However, the settlement agreement provided for the recovery of the costs of the Palouse Wind Project, subject to the 90 percent customers/10 percent Company sharing ratio, through the PCA mechanism until these costs are reflected in base retail rates in the next general rate case.

The settlement also provided that, effective October 1, 2013, base rates increased for Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from deferred natural gas costs of $1.6 million is being returned to the Company's Idaho natural gas customers from October 1, 2013 through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013 was 0.3 percent.

Further, the settlement provided that, effective October 1, 2013, base rates increased for Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from a payment to be made to Avista Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission system is being returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average electric rate increase to electric customers effective October 1, 2013 was 1.9 percent.

The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers do not impact the Company's net income.

The settlement agreement allows the Company to file a general rate case in Idaho in 2014; however, new rates resulting from the filing would not take effect prior to January 1, 2015.

The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.

The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. will refund to customers 50 percent of any earnings above the 9.8 percent. In 2013, the Company's returns exceeded this level and the Company will refund $2.0 million to Idaho electric customers and $0.4 million to Idaho natural gas customers. The period over which these amounts will be returned to customers has not yet been determined by the IPUC.

Oregon General Rate Case

On January 21, 2014, the Public Utility Commission of Oregon (OPUC) approved a settlement agreement to the Company's natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates will be implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $4.3 million). Effective November 1, 2014, rates for Oregon natural gas customers will increase on a billed basis by an overall 1.55 percent (designed to increase annual revenues by $1.4 million).

The billed rate increase on November 1, 2014 could vary slightly from that noted above as it is dependent upon actual costs incurred through September 30, 2014 related to the Company's customer information system upgrade and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. The estimated capital expenditures included in the general rate case settlement are $6.5 million and $2.0 million, respectively, for the two projects. If the actual costs incurred on the above projects are greater than the amounts contemplated in the general rate case settlement, the additional costs could be approved for recovery, subject to a prudence review.

The approved settlement agreement provides for an overall authorized rate of return of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent return on equity.

Bonneville Power Administration Reimbursement and Reardan Wind Generation Project

On May 9, 2013, the UTC approved the Company's Petition for an order authorizing certain accounting and ratemaking treatment related to two issues. The first issue relates to transmission revenues associated with a settlement between Avista Corp. and the Bonneville Power Administration (BPA), whereby the BPA reimbursed the Company $11.7 million for Bonneville's past use of Avista Corp.'s transmission system. The second issue relates to $4.3 million of costs the Company incurred over the past several years for the development of a wind generation project site near Reardan, Washington, which has been terminated. The UTC authorized the Company to retain $7.6 million of the BPA settlement payment, representing the entire portion of the settlement allocable to the Washington business. However, this amount was deemed to first reimburse the Company for the $2.5 million of Reardan project costs that are allocable to the Washington business, leaving $5.1 million to be retained for the benefit of shareholders.

The BPA agreed to pay $0.3 million monthly ($3.2 million annually) for the future use of Avista Corp.'s transmission system. The Company is separately tracking and deferring for the customers' benefit, the Washington portion of these revenue payments in 2013 and 2014 ($2.1 million annually). The Company implemented a one-year $4.2 million rate decrease for customers effective January 1, 2014 to partially offset the electric general rate increase effective January 1, 2014. To the extent actual revenues from the BPA in 2013 and 2014 differ from those refunded to customers in 2014, the difference will be added to or subtracted from the ERM balance. In Idaho, under the terms of the approved rate case settlement, 90 percent of the portion of the BPA settlement allocable to the Idaho business ($4.1 million) is being credited back to customers over 15 months, beginning October 2013, and the Company is amortizing the Idaho portion of Reardan costs ($1.7 million) over a two-year period, beginning April 2013.