Form 8-K





Washington D.C. 20549









Date of Report (Date of earliest event reported): August 26, 2011




(Exact name of registrant as specified in its charter)




Washington   1-3701   91-0462470

(State or other jurisdiction

of incorporation)



File Number)


(I.R.S. Employer

Identification No.)


1411 East Mission Avenue, Spokane, Washington   99202-2600
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: 509-489-0500

Web site:


(Former name or former address, if changed since last report)



Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:



Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)



Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)



Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))



Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))




Section 8 – Other Events

Item 8.01 Other Events.

Idaho Electric and Natural Gas General Rate Cases

On August 26, 2011, Avista Corporation (Avista Corp. or the Company) and all other parties filed a settlement agreement with the Idaho Public Utilities Commission (IPUC) with respect to Avista Corp.’s electric and natural gas general rate cases. Parties to the settlement agreement include the IPUC Staff and other intervenors. This settlement agreement is subject to approval by the IPUC.

As agreed to in the settlement stipulation, base electric rates for the Company’s Idaho customers would increase by an average of 1.1 percent, which is designed to increase annual revenues by $2.8 million. Base natural gas rates for the Company’s Idaho customers would increase by an average of 1.6 percent, which is designed to increase annual revenues by $1.1 million. The new electric and natural gas rates would become effective on October 1, 2011.

When combined with the Company’s other rate adjustments now pending before the IPUC, electric rates for the Company’s Idaho customers would decrease by 2.4 percent and natural gas rates for the Company’s Idaho customers would decrease by 0.8 percent. Other rate adjustments include the annual Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA), as well as the Bonneville Power Administration Residential Exchange credit and Demand-Side Management adjustments, which have no impact on Avista Corp.’s net income.

The Company’s original request filed with the IPUC on July 5, 2011 was for an electric rate increase of 3.7 percent, which was designed to increase annual revenues by $9.0 million. The Company also requested to increase natural gas rates by an average of 2.7 percent, which was designed to increase annual revenues by $1.9 million.

As part of the settlement agreement, Avista Corp. has agreed that it will not seek to make effective a change in base electric or natural gas rates prior to April 1, 2013, by means of a general rate case filing. This does not preclude the Company from filing annual rate adjustments such as the PCA and the PGA.

As previously disclosed, in June 2011, the Company entered into a 30-year power purchase agreement (PPA) to acquire all of the power produced by a wind project. It is expected that the wind project will have a nameplate capacity of approximately 100 megawatts and produce approximately 40 average megawatts with deliveries beginning in the second half of 2012. Under the terms of the settlement agreement, the Company would include all of the costs (Idaho portion) associated with the PPA through the PCA mechanism until such costs, subject to prudence review, are reflected in general rates.

The settlement agreement also 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 would be allowed to defer changes in operation and maintenance costs related to its 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 would compare 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 defer the difference from that currently authorized. The deferral would occur annually, with no carrying charge, with deferred costs being amortized over a three-year period, beginning in January of the year following the period costs are deferred. The amount of expense to be included for recovery in future general rate cases would 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.


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Date: August 30, 2011      

/s/ Mark T. Thies

      Mark T. Thies
      Senior Vice President
      and Chief Financial Officer